bluuebunny/crossref_metadata_2025_split huggingface dataset:
Frictional Pressure Loss Estimation of Water-Based Drilling Fluids at Horizontal and Inclined Drilling with Pipe Rotation and Presence of Cuttings
Authors: Ozbayoglu Evren M. , Sorgun Mehmet 
Published: January 2010

Abstract
Efficient removal of cuttings from the wellbore is one of the major considerations during a successful drilling operation. Fluid velocity is known to be the most dominating drilling parameter on hole cleaning. If the fluid velocity is lower than a critical value, a stationary bed develops, which leads to problems like pipe stuck, high torque-drag, increase in bottomhole pressure, increase in hydraulic horsepower requirements, etc. During a drilling operation, besides the fluid flow and presence of cuttings, there is pipe rotation. Determining the pressure losses in such a complex system is very difficult. This study aims to estimate the frictional pressure losses in horizontal and highly inclined wells considering pipe rotation and presence of cuttings. Extensive cuttings transport experiments have been conducted on METU Cuttings Transport Flow Loop using pure water as well as numerous water- based muds consist of different concentrations of xanthan biopolimer, starch, KCl and soda ash, weighted with barite for various inclinations, flow rates, rate of penetrations and pipe rotation speeds. Pressure drop within the test section, and stationary and/or moving bed thickness are recorded besides the other test conditions. Observations showed that, pipe rotation has a significant influence on decreasing critical velocity required to prevent stationary bed development, especially if the pipe is making an orbital motion. However, after a certain pipe rotation speed, no additional contribution of pipe rotation is observed on critical velocity. Moreover, a reduction in the pressure drop is also observed due to the bed erosion while rotating the pipe, when compared with no pipe rotation case under the similar drilling conditions. Empirical correlations are developed based on the experimental data for estimating pressure drop. It is observed that the results obtained from the correlations are reasonably accurate, within an error range of 10% for estimating pressure drop, when compared with the experimental observations.
Collaborative Well Planning and Optimization of Well Placement: A Case Study From Mangala Field Development, Rajasthan India
Authors: Rosland Habil Akram , Peytchev Peter , Sarkar Shibatosh , Mukherjee Supriya , Govind Balu , Malik Sumit D. 
Published: January 2010

Abstract
This paper discusses the approach of Cairn Energy India Ltd. (CEIL) in the use of a state of the art technology that integrates all relevant data scenarios for designing and planning development wells in the Mangala field of Western Rajasthan, India.
To improve the quality of the well planning process, CEIL has realized the importance of a collaborative well planning environment, which was implemented by means of its world-class 3D visualization center that enables multidisciplinary well planning workflows to take place in the subsurface environment. The environment includes physical infrastructure, new technology, and data. A fully functioning collaborative well planning environment enables the drilling team to plan wells using engineering tools, including drilling target definition and refinement, well pad positioning, and wellbore position uncertainty, based on company anti-collision policies, with geosciences team capacity to validate those designs against their subsurface data.
The Mangala field development process has established the success of CEIL with rapid, multisolution iterations well planning to the entire asset team and improved wellbore positioning based on potential engineering constraints. This process takes the optimum reservoir drainage into account with possible geological hazards and reduces the operational cost by complementing technical expertise across the broad disciplines. The workflow aids wellbore and drilling optimization and improves decision making and collaboration throughout the field development sequence.
The paper explains the detailed aspects of collaborative well planning and optimization of well placement methodology used for Mangala field, which includes 11 horizontal wells that were largely designed as shallow extended reach drilling (ERD) wells. It demonstrates how this method significantly improved the mutual workflow between departments and increased efficiency. This paper also describes the interactive design that dramatically decreased the cycle time in planning more than 160 wells in the field, which contributed to effective development plans and well placement based on geological, drilling, and completion requirements.
Hydrate Formation and its Influence on Natural Gas Pipeline Internal Corrosion Rate
Authors: Obanijesu Emmanuel O. , Pareek Vishnu , Tade Moses O. 
Published: January 2010

Abstract
Hydrate formation along the natural gas pipeline has been identified as a serious threat to the survival of oil and gas industry. The formation if not quickly removed may plug the flowline to collapse the system. This problem costs the industry billions of dollars in revenue loss annually. While all the available literatures on hydrate formation process have focused on its ability to plug the flow line, there has been little or no recognition of its ability to initiate internal corrosion of the pipeline which is a bigger problem to the industry, hence, the importance of this study. This work focuses on this new area for research interest aimed at revolutionalizing the field of corrosion science and technology.
In this study, the composition of the lattice which includes methane (CH4), carbondioxide (CO2) or hydrogen sulphide (H2S) and water molecules (H2O) amongst others is considered. These gases have the ability to easily undergo chemical and/or electrochemical reactions with the pipeline's internal surface while the lattice is in place. The reaction(s) will easily initiating corrosion of the pipe. The study further identifies the fact that even after the successful removal of the hydrate, the initiated corrosion process may continue with the continuous flow of the fluid within the pipeline thereby leading to gradual degradation of the material and deterioration of the pipe's integrity. Over time, the pipeline will begin to leak and/or may undergo full bore rupture (FBR). This, apart from the economic consequences will also generate environmental and political consequences and may lead to complete replacement of the pipe-length.
Various management schemes including the necessity for the industry to heavily invest in research and development are recommended.
New Silicon Copolymers for Efficient Demulsification
Authors: Phukan Monjit , Koczo Kalman , Falk Benjamin , Palumbo Antonio 
Published: January 2010

Abstract
Organomodified silicones, which are used as effective demulsifying agents, are generally based on a polysiloxane backbone with polyether or other organic substitutions attached to it. A new silicone-based demulsifier was synthesized that contains polyether in the backbone and silicon-containing substituents. Interfacial tension (IFT) measurements with a model oil system showed that the new material has better interfacial activity (~5mN/m) than the traditional structures (10-14mN/m). This low interfacial tension can be one of the important parameters for coalescence of water drops in water-in-crude oil emulsions. Bottle tests with crude oil emulsions confirmed that the new demulsifier also can provide better demulsification performance with faster water drop and lower bottom solids and residual water in the dehydrated crude after demulsification.
Effect of Suspended and Dissolved Substances on Formation and Dissociation of Gas Hydrates
Authors: Laik Sukumar , Mandal Ajay , Saw Vikash Kumar , Gupta Pawan 
Published: January 2010

Abstract
In the permafrost region and ocean bottom where gas hydrates are formed in the form of nodules mound etc, it mixes up with the clay and other substances at subsea soil. Naturally its property gets changed during formation as well as dissociation. Therefore the present study aims at studying the effect of extraneous material like Bentonite with different composition and surfactant on formation and dissociation of gas hydrates. Extensive observation of pressure temperature equilibrium during formation and decomposition of methane hydrate under different conditions have been made. The effect of bentonite and anionic surfactant sodium dodecyl sulphate (SDS) on the rate of hydrate formation is thoroughly investigated in this work. Three different concentrations (3%, 5%, and 10%) of bentonite are tested followed by three different concentration of SDS (300 ppm, 500 ppm, 1000 ppm) in unique concentration of 5% bentonite. For comparison purpose, the formation and dissociation of pure water has been also conducted. All the experiments are started with same pressure i.e. 440.2 psi. It has been found that addition of Bentonite inhibit the hydrate formation as compared to water, however SDS speed up the hydrate formation effectively.
Immiscible Hydrocarbon Wag: Laboratory to Field
Authors: Ramachandran Kudal Purakkal , Gyani Omkar Nath , Sur Sidhartha 
Published: January 2010

Abstract
A sandstone reservoir at a depth of 2800 m in a western India onshore field contains highly under saturated light oil of 470 API with viscosity of 0.2 cp. The reservoir has a permeability ranging 50 to 300 md and high temperature of around 130 Deg C. It is exploited by supplementing the partial water drive with water injection. Water injection was initiated in the early part of its producing life and has recovered more than 30% of OIIP. Meanwhile, availability of natural gas from deeper reservoirs in the field initiated a thinking process to examine the processes involving both miscible and immiscible displacement with gas injection to improve the recovery factor from the reservoir. The reservoir was not found suitable for miscible process due to higher miscibility pressure as compared to prevailing reservoir pressure of 250 Kg/cm2. Viability of immiscible WAG was ascertained through both laboratory investigations and numerical simulation prior to its testing on a pilot scale in the field. The process resulted in an increase in oil production along with reduction in water cut from the pilot and offset wells. Encouraging pilot results led to the decision of expanding the process to the entire field. The paper also evaluates the effects of different critical parameters on the recovery factor from immiscible WAG process through reservoir simulation studies.
Drilling Hazard Mitigation Technologies Key in Eliminating Non-Productive Time in Challenging Wells
Authors: Gala Deepak M. , York Patrick , Pritchard David , Dodson James K. , Dodson Ted , Rosenberg Steven , Utama Budi 
Published: January 2010

Abstract
Cost overruns can easily manifest during well construction because of unexpected issues including lost returns, differential sticking, and narrow pore pressure/fracture gradients. To better plan for potential overruns, operators sometimes earmark 10 to 25% of the Authorization for Expenditures (AFE) to cover the unexpected costs, which can significantly affect drilling budgets. Technical and operational risks versus the potential return on investment (ROI) are critical factors in determining whether a project will proceed.
Too often the best drilling practices used to address trouble zones are limited to a few conventional methods with a narrow range of effectiveness. Also, a lack of rock mechanics knowledge can prevent the most efficient solution being applied.
Some operators are implementing planning programs that assess and integrate the latest processes and technologies to address drilling risks up-front. Cutting-edge technologies such as managed pressure drilling methods, drilling with casing, drilling with liners, and solid expandable casing have been highly effective. Implementing proactive evaluation processes and applying the latest tools and techniques can efficiently address operational risks and trouble zones to ultimately reduce nonproductive time (NPT) and associated costs.
Employing common practices and technologies that are typically ineffective and that drive up NPT cost should be considered unacceptable. Common-sense, well-construction evaluation processes that are used with validated conventional and new technologies have proven their worth by reducing expenditures and risks—preventing the loss of wells and increasing the operator’s ROI.
This paper reviews real drilling challenges that have been encountered and the common practices that were employed to address these drilling hazards. Also this paper compares and contrasts how these same circumstances have and can be addressed much more efficiently with engineering evaluation processes that help determine the best drilling tool and/or technique to mitigate risks and reduce NPT.
Elegant Completion Optimization and Enhanced Production With Borehole Images and Advance Production Logs: An Integrated High-End Technology Approach, Bombay Offshore, India
Authors: Sinha R. K. , Sikdar K. , Avtar R. , Majithia P. P. , Baishya R. C. , Pandey A. , Shrivastava C. , Roy D. B. , Kumar A. 
Published: January 2010

Abstract
Evaluating critical petrophysical and geological properties is the key in determining completion strategy. To optimize completions in a highly heterogeneous formation, segmented completion design was planned. Integration of borehole images with conventional openhole logs and dynamic mud loss data distinguished between facies and subfacies which can have different flow behaviors. Based on the integrated formation evaluation, placement of swell packers, slotted liners and blind liners were decided in the study area.
Advanced processing results from the borehole images (e.g. secondary porosity, connectedness, etc.) were used to evaluate the heterogeneity in the drainhole, suggesting the zones that needed special attention for completion planning. This type of segmented well completion in a horizontal well was decided to compensate for the effects of variable vug size distribution and encountered fractures and dissolution seams.
With this completion design being the first of its kind for the operator, the first objective was to evaluate its efficiency (sealing efficiency of the swell packers). The conventional production logging sensors were combined with advanced electrical and optical probe, along with the "beyond-the-pipe" vision of the neutron tool to produce a consolidated and accurate image of the flow profile. This not only helped in compartmentalized production profiling of the well, but also made it possible to evaluate the sealing efficiency of the swell packer.
A diagnosis was made based upon the results, and a remedial plan was suggested. All swell packers were found to be effectively sealing, and couple of water humps were detected to be acting as barrier to flow. It was decided to increase the drawdown to knock out the water hump, and it immediately led to a significant increase in production. Being the first such job in a developmental field, this study developed a method for an innovative completion strategy that helps production enhancement.
Challenge Of Completion In Low Productive Grey Fields
Authors: Srivastava A.K. , Mandal B. 
Published: January 2010

Abstract
In context with the low productive fields of Western Offshore where the production in the range of 500 to 1000 BOPD the field specific completion techniques in commensurate with the reservoir characteristic is a big challenge.
The main reservoir of Western Offshore is a fractured limestone reservoir with high degree of heterogeneity. In general, such reservoirs offer the best prospects for open hole completions that offer several benefits including cost effectiveness and ease of execution. But these long horizontal open hole adds major risk component to well design for such heterogeneous, water flooded carbonate reservoirs and increases the potential risk of exposing undesirable geologic portions such as water filled fracture networks, zones of high water saturation, high permeability thief zone intervals etc. and decline in production generally happens due to the sudden increase in water break-through and hole collapse attributed due to the following reason: High degree of Resistivity difference (heterogeneity) along the horizontal open hole.Presence of shale in some portion of the open hole section.Water coning from heel due to high drawdown.
In some reservoir of Bassein field there are thin oil rim with a huge overlain gas cap and underlain water.
It is important to establish a cost effective completion techniques to exploits such grey fields comparing highly expensive smart wells.
A Coil Tubing Friendly Segmented Completion with open hole packer along with coil tubing operated Sliding Sleeve or without sliding sleeve / Perforated liner has been established as an economic and successful completion to mitigate the aforesaid problems. The use of uniform flow system in conjunction with open hole packer may be an appropriate and economic method for exploiting oil from thin oil rim.
This paper contains cost effective case histories of reservoir specific completions and looking for future challenges.
A Thermal Gas Production System from Methane Hydrate Layers by Hot Water Injection
Authors: Sasaki K. , Ono S. , Sugai Y. , Tenma N. , Ebinuma T. , Narita H. 
Published: January 2010

Abstract
A gas production system by injecting hot water into a methane hydrate layers with lower aquifer under the sea bottom has been studied using with horizontal wells in radial arrangements. In order to overcome extremely low permeability and large dissociation heat of the MH layer, the system forming dissociated chamber with high permeability and communication to lower aquifer has been proposed and evaluated by physical and numerical models. The numerical simulations were successfully matched with experiments using the physical model. Moreover, numerical simulations of gas production by the hot water injection into a field of methane hydrate sediment using dual horizontal wells 500 m in length were carried out for a methane hydrate reservoir of 15m in layer thickness, 60% of hydrate saturation, 100 and 25 md in horizontal and vertical absolute permeabilities, respectively. In this study, after getting communication between hot water chamber and lower aquifer, a gas production scheme for the area of 1km×1km has been proposed by using radial flow between different horizontal well pair through lower aquifer. At the beginning, dual horizontal wells was preheated by hot water circulation in the wells for 90 days to get communication of area between two horizontal wells. After gas production with four pairs of dual wells for one year, radial hot water flow can be used to make the chamber expand in horizontal section of the reservoir. The simulations were performed under the following conditions: hot water temperature of 85°C, injection rate of 2000 ton/day, horizontal wells 500 m in length, and a hydrate layer 15m in thickness with vertical absolute permeability of 25 md horizontal one of 100 md and methane hydrate saturation of 60%. The cumulative gas production during 15 years, it was estimated as 1.3×108 std-m3 during 15 years by using with the injection scheme with radial hot water flow between different wells pair after one year.
Impact of Changing Mdea Parameters on Absorption of H2S and CO2 and its Implications—A Case Study of Hazira Plant
Authors: Mehta Kunal , Jain P. K. , Pathak S. K. , Panwar M. L. 
Published: January 2010

ABSTRACT
On account of the poisonous nature of Hydrogen Sulphide (H2S) gas, removal of H2S or sweetening of natural gas is one of the most critical activities in gas processing. For sweetening of natural gas, Methyl Di-Ethanol Amine (MDEA) is successfully used all over the world. In MDEA based gas sweetening units, removal of H2S is carried out in the Absorber Column using counter – current principle. Due to acidic nature of H2S and CO2 both, removal of H2S is accompanied by absorption of CO2 by MDEA. For regeneration, MDEA is heated in the Regeneration Columns where H2S and CO2 both are liberated as Acid Gas.
The basic aim of the gas sweetening process is to remove H2S almost completely with minimum absorption of CO2 in MDEA in order to reduce the quantum of Acid Gas generation. To achieve these objectives temperature, concentration and flow rate of MDEA solution along with contact time and other operational parameters are adjusted and optimized. For improving the effectiveness and efficiency of the process, a study on Impact of changing MDEA parameters (temperature and concentration) on absorption of H2S and CO2 was carried out.
The study revealed that with change in parameters of MDEA, the H2S content and the CO2 content of rich MDEA changed appreciably. Hence by proper optimization of different parameters the absorption of H2S and CO2 in MDEA can be controlled to suit to our need and operational limitations. CO2 alone accounts for nearly 90 % of the volume of the acid gas. Restricting the absorption of CO2 in MDEA column itself can control the generation of acid gas. Lower temperature of MDEA along with lesser contact time will mitigate the dissolution of CO2 in MDEA solution. As in CO2 - MDEA reaction, the rate determining process is the dissolution of CO2 in water, by merely restricting the dissolution of CO2 in water, volume of acid gas generated can be reduced.
Hence by maintaining proper parameters of MDEA solution, effective removal of H2S along with controlled generation of acid gas is possible which in turn can mitigate several operational problems. Controlled generation of acid gas will not only lessen the load of acid gas treatment but will also have significant financial implications.
Implementing Knowledge-Management Systems: Collaboration Tools Create Efficient and Synergistic Operations Between Oil-Service and Energy Companies
Authors: Jaripatke Omkar , McElroy Monty , Potala Srikanth 
Published: January 2010

Abstract
In today’s world, the success of a corporation is closely linked with the success and health of the industry itself. In the oil and gas industry, achieving long-term technology and performance goals is dependent on the synergistic sharing of efficient "cost savings-driven operations" through knowledge collaboration between global oil-services and energy companies. Knowledge-management systems (KMS) are a great tool to collaborate and integrate a knowledge base between global oil and energy and service companies. In the global marketplace, considering the bleak outlook for the economy, successful oil-service companies must tailor their business models to continually increase efficiency for proven revenue-generating processes by reducing costs associated with operations, while increasing the service quality to the global energy companies. On the other hand, both the oil-service and the energy companies can benefit from the knowledge-sharing of the technology/services and logistics.
The concept of knowledge management (KM) has been implemented in global oil-service and energy companies by creating KM communities in various service segments. By implementing KMS, the scope of KM teams has expanded from the original intent to where the KM portals are the first choice for collaboration in diverse projects on a daily basis to bring together different ideologies and functionalities within a company to achieve the business objectives discussed above.
This paper discusses the need, importance, benefits, and implementation methodology for a shared KMS platform between a global oil-service company and a global energy company. It discusses, in detail, the required setup on both sides for successful project initiation and implementation. Additionally, the key stages for this joint KM mechanism to work are also discussed: (1) the initiation stage, (2) development stage, (3) implementation stage, and (4) expansion stage.