bluuebunny/crossref_metadata_2025_split huggingface dataset:
Determination of 20-in. Conductor Setting Depth in Deepwater Wells in the Krishna-Godavari Basin Offshore India
Authors: Holasek Fred R. , Singh Raj K. , Shanker Shashi 
Published: December 2007

Abstract
Deep water well design and drilling is challenging due to the narrow separation between pore pressures and fracture pressure. Comparing the fundamentals of deep water well design to shallow water / onshore well design is dramatic. Once the pore pressures and fracture pressures have been modeled, the shallow water / onshore well design begin with choosing the desired casing size at total depth. Establishing the desired casing size at total depth for shallow water / onshore wells for the most part determines the casing points from total depth to surface. This is often referred to as the "Bottom-Up" well design.
On the contrary, deep water well design begins with the selection of the 20″ conductor depth. Once this depth has been selected, it determines subsequent casing points. This is commonly referred at the "Top-Down" well design. The deeper this string is set, the deeper the subsequent casing strings can be set. Extending this depth can eliminate entire casing strings. The challenge becomes to safely set the 20″ conductor as deep as possible.
A major deepwater drilling program has successfully drilled more than 19 wells in deep water in the Krishna-Godavari Basin. The setting depth of the 20″ casing has been extended using 3-D seismic, seal capacity analysis, shallow pore pressure prediction, shallow fracture pressure prediction and "pump and dump".
Once the 20″ conductor has been set, which is predominately in the very plastic Godavari clay, determining the maximum mud weight is also a challenge. The proper analysis will allow the next casing string to set deeper.
Although deep water well design in the Krishna-Godavari Basin should not be considered routine, the appropriate pre-drill analysis has significantly reduced the risks and costs of deep water drilling.
The Special Challenges of Killing a Blowout Caused by Illegal Oil Bunkering
Authors: Oudeman P. 
Published: December 2007

Abstract
Illegal oil bunkering, a euphemism for oil theft, has become a wide spread practice in the Niger Delta. Since these activities are not accompanied by the usual safety measures for oil production, dramatic accidents happen with consequences such as the loss of many lives and full-scale blowouts. A typical problem encountered in combating these blowouts is that no data are available on pressures, rates and fluids in the well prior to the blowout. Likewise records on well operations leading to the event are obviously missing. Hence the design of the kill will have to be based on historic data, on site observations and assumptions, which have to cover every possible scenario.
This case history describes how a blowout caused by illegal oil bunkering was killed successfully within the boundary condition of minimizing the impact of the blowout and the kill on the sensitive environment. The design of the kill, based on limited data and numerical simulations to determine the approach with the highest probability of success, planning and execution of the kill job will be discussed.
A post-kill analysis demonstrates that the design calculations accurately predicted the actual progress of the kill job. This increases confidence in these calculations for future application in emergency situations.
Improved Oil Recovery by Seismic Vibration: A Preliminary Assessment of Possible Mechanisms
Authors: Huh C. 
Published: December 2007

ABSTRACT
Use of seismic vibration has been proposed as a low-cost IOR method, with reports of some successful field results. A key difficulty with the method is that its mechanism for oil recovery is not yet known, and accordingly, process performance prediction and reliable project design is so far not possible. In this study, a critical review of literature on the field and laboratory results and theoretical modeling work is first made. Employing a simple pore-level model and the well-established capillary number correlation, mobilization of waterflood residual oil by seismic vibration is shown to be unlikely, confirming earlier coreflood data.
A more likely mechanism for IOR is that vibration squeezes out the oil bypassed by earlier recovery methods, due to reservoir heterogeneity. While it is quite difficult to bring the injection fluids to the low-permeability zones in a highly heterogeneous reservoir, vibrational wave can transmit effectively through both high- and low-permeability zones. When a seismic vibration propagates through a heterogeneous reservoir, the pore pressure response in different permeability layers becomes different, generating a transient pressure difference and crossflow between the layers, potentially squeezing out oil from the low-permeability zones. The rock deformation and fluid flow equations are coupled to describe the effects of low-frequency oscillatory poroelastic deformation on crossflow. Improved oil recovery due to vibration-induced crossflow is approximately estimated. Our assessment that seismic vibration recovers only the oil bypassed due to reservoir heterogeneity may explain why the method's success is rather erratic, since accurate advance characterization of reservoir heterogeneity and the bypassed oil is inherently difficult. On positive side, seismic vibration may improve access of IOR chemical to low-permeability zones such as matrix portion of naturally fractured reservoirs, for better oil extraction from hard-to-access tight matrices.
Another important question that needs to be addressed is how to deliver vibrational energy effectively to a large volume of reservoir where the oil is. Fluid pressure oscillation damps down quickly in porous media and even the rock deformation wave attenuates significantly. One possible way is to transmit rock displacement wave continually so that its accumulation can form resonance in the reservoir. The resonance generation with the reservoir length scale as the resonance wavelength requires a very slow wave, and recent literature on the subject is discussed.
Solid Expandable Tubulars Provide Substantial Value to Existing Wells
Authors: Rivenbark Mark 
Published: December 2007

Abstract
Major operators are using solid expandable tubulars in existing wells to tap added reservoir pay. This use of the technology is the result of close collaboration between the contractor and the operator, particularly the reservoir engineering and drilling departments. Together they have devised plans that maximize the return-on-investment (ROI) and the long term sustainability of the reservoir.
The use of solid expandable tubulars to provide a larger drainhole in existing wellbores is proving to be a considerable benefit to many operators. Aside from the obvious production gains from a larger borehole, the operator also gains on the drilling side of the equation. The larger inside diameter (ID) through the solid expandable casing allows for the use of larger drilling tools. These larger tools typically drill farther and faster than smaller tools and suffer far less non-productive time due to failures.
This paper reviews the value derived from using solid expandable tubulars in the casing design of existing wells with actual case history data. Further, the paper details ancillary benefits that can be factored into the value gained by the operator.
LWD Formation Pressure Testing Allows Decision Making While Drilling
Authors: Hahne Ulrich , Kaniappan Aravindh , Pragt Jos , Buysch Arno 
Published: December 2007

Abstract
The potential operator cost efficiencies of acquiring valid formation pressure data while drilling are becoming more influential in deciding the value proposition of a wireline reservoir characterization program. Cost efficiencies may indeed be pivotal but importantly, the benefit of acquiring pressure data in real time needs equal consideration, as a number of novel applications now exist.
The paper will use case histories and lessons learned from experience with 300 logging while drilling (LWD) formation pressure runs in different operating areas including Asia Pacific to demonstrate the applicability to conventional formation pressure applications, traditionally acquired with wireline formation testers upon reaching section or well total depth (TD). These are the determination of formation pressure, fluid contacts, reservoir connectivity, and near-wellbore mobility. We discuss novel real-time applications and benefits for drilling and subsurface teams, such as mud weight management, safe selection of casing points, calibration of pore pressure predictions, selection of wireline sampling points, reservoir monitoring, geosteering, and obtaining data in high-risk wells.
Incorporating formation pressure testing into the drilling process presents challenges to perform measurements in a timely manner, as well as the need for continuous circulation while testing to ensure wellbore safety.
Providing this type of while-drilling formation evaluation data with an LWD tool allows a continuous approach to data evaluation and decision-making. The ability to measure accurate LWD formation pressure data in a variety of hole sizes represents a significant opportunity for safe and cost-efficient wellbore construction, especially in challenging environments.
Drilling Fluid Additives and Engineering to Improve Formation Integrity
Authors: Goud M. C. , Joseph Givi 
Published: December 2007

Abstract
Fracture propagation is a very commonly seen phenomenon when using synthetic-based drilling fluids (SBM) in areas of narrow drilling windows. Consequently, deepwater drilling has brought lost circulation control to a more critical level. This is further compounded by other deepwater drilling-related problems such as narrow pore pressure/fracture gradient windows, cold drilling fluid temperatures, high equivalent circulating densities (ECD's), high cost per barrel and a higher cost for lost rig time/non productive time.
Induced fractures pose an even more complicated problem due to the various factors involved. These fractures can be influenced by to the nature of formation, drilling and/or by mechanical effects. One condition of paramount importance in sealing induced fractures is having the lost circulation material (LCM) effectively isolate the tip of fracture.
In its deepwater operations, Reliance introduced the use of crystalline graphite in conjunction with sized calcium carbonate into the SBM to strengthen the formation. Graphite is utilized to seal and isolate the near wellbore fractures the tip along with optimizing the rheology of the SBM. The particle size selection of the bridging particles was engineered based on software to optimize the bridging and sealing effect, which employed knowledge of the pore throat sizes and the permeability of targeted formations. This has resulted in elevating the formation integrity test pressure (FIT) and helping drill longer sections, which in normal circumstances would have been a difficult task.
The authors will discuss the design of these drilling fluid additives and their impact. Also outlined are the treatment techniques necessary to ensure minimal formation of induced fractures along with the engineering tips required to ensure successful application of such treatments. The authors will also review the results of actual formation strengthening seen in one of their exploration wells.
Effect of Pressure in a Well With a Vertical Fracture With Variable Conductivity and Skin Fracture
Authors: Gonzalez-Chavez Miguel Alejandro , Cinco-Ley Heber 
Published: December 2007

Abstract
A mathematical model was developed to study the behavior of a well with variable finite-conductivity and skin fracture, for a vertical fracture in an infinite slab reservoir.
The solution is valid for slightly compressible fluid and gas fluid applying the pseudo-pressure concept. The constant rate with wellbore storage and constant pressure are the production modes considered. Curves type are used to showsthe effect of the changes of conductivity and skin near the well and in the extreme of the fracture. A field test was analyzed to detect the changes of the properties. This model is a tool to analyze real cases when the fracture properties are affected during the productive life of the well.
Thermal Simulation and Economic Evaluation of Heavy-Oil Projects
Authors: Rangel-German E. R. , Camacho-Romero S. , Neri-Flores U. , Theokritoff W. 
Published: December 2007

Abstract
Many recent hydrocarbon discoveries in the Gulf of Mexico are heavy and extra-heavy oils. Additionally, given the imminent decline of lighter crude oil fields such as Cantarell (the primary Mexican oil field), it seems that most of the crude oil production in Mexico, in the midterm, will come from heavy-oil reservoirs. The need to analyze the feasibility of unconventional recovery methods becomes readily clear. This paper presents a methodology to evaluate heavy-oil projects using thermal simulation and economic evaluation.
Thermal recovery methods are used to exploit heavy oil reservoirs, where oil viscosity is very high and mobility low at the reservoir temperature. It is desirable to reduce the oil viscosity by increasing its temperature. An affordable and easy-to-implement technique is by means of heaters or an electric cable.
This paper presents the results of this methodology, which includes thermal compositional simulation of a synthetic grid model, with the fluid properties mimicking those of heavy oils recently discovered in the marine region of the Gulf of Mexico.
PVT analysis, viscosity curves, rock properties, relative permeabilities, capillary pressure, and reservoir pressure and temperature are also studied.
The economic analysis was performed using current capital expenditures for drilling and completion and operating and maintenance costs. Different scenarios for costs, oil and gas prices and capital investment were studied. A sensitivity analysis was performed to determine the variables having the highest impact on the economic value of the project.1
This methodology showed that introducing heat by means of an electric cable is a technically viable and profitable alternative, even for projects under off-shore economic premises, which are considerably higher than those for onshore projects. Implementing the heating from the beginning of the project and continuing to its completion, was found to be the most important factor for the economic success of this method.
HP/HT Cement System Design—East Coast Case History
Authors: Haidher Syed , Kale Samir , Affes Sami , Nair Suresh Kumar 
Published: December 2007

Abstract
Cement Systems require conformance of specific parameters for the longevity of the system placed as a sheath. Challenges of the system design are exacerbated considering the environment for placement of the sheath. HPHT cement systems require special design attention, and the authors propose to share one such case history in designing of the HPHT system for Eastern India Offshore.
HPHT cement systems require not only modified testing procedures, but products also. HPHT cement system products are required to withstand BHST temperatures for the life of the well without considerably altering the slurry system properties. Modified test procedures and products requirements for slurry system bring additional logistical challenges like preparation and availability of right cement blend for testing and preparing the slurry system for the application.
Considering the temperature gradient of 2.23°F/100ft, bottom hole static temperature (BHST) for the 7" liner job was 467°F. The mud weight for the section was planned between 14-16 ppg (1.67 to 1.9 sg). Computed BHCT alone was considered inadequate and determination of the hot spot in the wellbore was required. Computerized simulator was used for the purpose. Results show that the hot spot temperature predicted by the simulator was higher than the computed BHCT and the depth of the hot spot was shallower than TVD as normally anticipated. The simulator runs are recommended for determination of hot spot for HPHT testing of cement systems in particular. The simulator considers effects of various fluids pumped and their contact times along with the heat capacities during the application.
Product choice for preparation of the Cement systems used earlier for the high temperatures encountered in Western India offshore were reviewed and preliminary testing was carried out on the basis of the prognosed temperature. However predictions from the temperature simulator yielded higher temperatures for the East coast well. This required a different product set for the cement system design.
The authors feel that the review of this case history and the design challenges at this technology meet shall potentially benefit the design engineers in understanding and enhancing their knowledge about design practices for HPHT cement systems.
Expandable and Contractable Bit
Authors: Agarwal Sharad Ashok 
Published: December 2007

Abstract
EC bit is an expandable and contractable bit a new concept of drilling the boreholes of different radii at different depths and in zone of our choice without changing the size of bit and without tripping operations.
During conventional drilling boreholes of different radii at respective depths are being drilled. In order to drill boreholes of different radii bits of different sizes are manufactured which consumes tremendous amount of material, time and finally the cost. In order to face this challenge here a tool has been proposed which uses single comprehensive bit size to drill complete well. The mechanism of this tool is based on the concept of rack and pinion system. The rotation of gears (pinions) and movement of the racks will help us to drill the borehole of radii of our choice.
With the help of this tool the important advantage is that the drillstring is not changed every time, only one size of drillstring is being used to drill complete well. This revolutionary idea of manufacturing ONLY ONE BIT SIZE will cost the drilling contractor a tremendous reduction in costs of bits. The other advantages include enhance production, reduction in skin damage and control the problem of sand production.
Benchmarking the Cycle Speed of an AC-SCR Drilling Rig with Special Reference to Upper Assam Operation
Authors: Gogoi G. , Hussain A. 
Published: December 2007

Abstract
Benchmarking can be done for the various processes involved during rig up, rig down and drilling operation of an AC-SCR (E-1400) land drilling rig operated in Upper Assam Development Oil Field for productivity enhancement. An endeavor was made in OIL INDIA LTD to benchmark the drilling cycle time for all AC-SCR (E-1400) land rigs by reducing the Non Commercial Time and hence to increase the Cycle Speed.
In this benchmarking, three main areas of a Drilling Cycle were considered.
Benchmarking the rig down/rig move and rig up operation of an AC SCR (E-1400) drilling rig. This area is a major contributor for the Non-Commercial Time of a Drilling Cycle, which is by average, is about 30% of the Total Cycle. Benchmarking the commercial time (i.e. when the rig is busy in making the hole including the trip time). Trip time is a major portion of Non-Commercial Time within the commercial time. This contributes about 20% of the total drilling time. This was done by using intelligent technology and system for drilling performance. Since it is a fully developed field, therefore we have benchmarked the production testing time as 15 days for two ‘sands’. This includes wiper trip, CBL / VDL, changing over & lowering of well fluid level, and finally perforation & observation. By introducing the multi-skill performance technique among the crew. This concept helps to increase the efficiency & effectiveness of the crew deployed in the rig. This in turn helps in reducing break down time.
The natural environmental factors prevailed in upper Assam areas were considered while bench marking the drilling cycle time.
It has been worked out that by implementing the benchmarking of the whole cycle, a rig can complete about 3.47 cycles per year against 2.48 cycles per year before benchmarking.
Economic Pumping Technology for Coalbed Methane (CBM), Stripper Oil, and Shallow Gas Well Deliquification
Authors: Dickey Michael W. 
Published: December 2007

Abstract
Operators of shallow, low flow oil and gas wells have commonly relied on conventional beam pump and other artificial lift methods to produce these types of wells. Often, the use of these pumping systems results in inefficiencies, short run-life and environmental challenges that affect the overall economics of the operation.
A hybrid artificial lift system has been developed to allow operators of shallow, low flow oil and gas wells the opportunity to produce the wells in a much more economical fashion than beam lift or other conventional methods. This paper introduces the technical aspects of the system, its operation and deployment techniques, and the power savings it realizes in comparison to beam lift and other traditional lift systems.
The Hydraulic Diaphragm Electric Submersible Pump (HDESP) uses a technology that offers a number of benefits to operators. The system's hybrid design advantageously combines the beneficial features of both electric submersible pumps (ESP) and hydraulic diaphragm pumps (HDP). Both of these types of systems are widely accepted in their respective industries.
Laboratory tests and deployment of the HDESP in producing wells confirm the systems capabilities in vertical wells up to 2500 feet in depth with production rates less than 200 BFPD. Ongoing design engineering has objectives of greater depths and higher volumes. Heat issues commonly associated with electric submersible motors are also being addressed.
Abrasives and gas handling comparisons are made between ESPs and beam pumps. Procedures optimizing HDESP reliability within adverse wellbores are also described.
Power cost studies indicate that the HDESP can reduce electrical cost by as much as 50% compared to beam pumps and water-well type ESPs. The net positive suction head (NPSH) requirement is considerably less, allowing an operator to drawdown fluid levels very close to the pump intake. This offers potentially significant production benefits to the producer.
At the conclusion of the paper, readers will have a thorough understanding of the function of the HDESP system, its performance successes and failures, suitable target applications, deployment techniques, and the overall potential for economic benefit the system brings.