The Experts below are selected from a list of 297 Experts worldwide ranked by ideXlab platform

A. Bahoumina - One of the best experts on this subject based on the ideXlab platform.

  • Cold-forged connector ties back well risers in Congo field
    Oil & Gas Journal, 1997
    Co-Authors: W.m. Taylor, M. Tison, A. Bahoumina
    Abstract:

    The tieback of eleven 10 3/4-in., high-pressure risers in Elf Congo`s offshore N`Kossa field used a cold-forge tieback system to create a metal seal. The time-saving tieback method allows for placing the risers in residual tension. The installation work was completed in the fall of 1995. Average time to complete the 10 3/4-in. Casing tiebacks, including test and nipple-up and nipple-down times, averaged 52 hr/well. Tiebacks for all three Casing strings averaged 90 hr for all surface and subsea operations including BOP test and nipple-up/nipple-down time. Metal sealing of the primary Casing Annulus has been made practical because the offshore industry has gone toward compact-wellheads and hanging of the completion on a mandrel. Hanging the completion on a mandrel, however, has it own set of considerations. Exact riser length may be difficult to predict before running because the riser must first be locked into the mudline Casing hanger and then landed out on the support shoulder in the surface head. Also, a general desire is that riser tieback strings should be in tension after installation. This is not always easy with a passive or dumb hanger and fixed should configuration. Threaded, adjustable mandrel hanger systems exist but can require verymore » close Casing string space-out to achieve the desired residual riser tension. The paper describes the objectives, forged sleeves, running sequence, cold forging, and the prototype test.« less

  • Cold-forged connector ties back well risers in Congo field
    Oil & Gas Journal, 1997
    Co-Authors: W.m. Taylor, M. Tison, A. Bahoumina
    Abstract:

    The tieback of eleven 10 3/4-in., high-pressure risers in Elf Congo`s offshore N`Kossa field used a cold-forge tieback system to create a metal seal. The time-saving tieback method allows for placing the risers in residual tension. The installation work was completed in the fall of 1995. Average time to complete the 10 3/4-in. Casing tiebacks, including test and nipple-up and nipple-down times, averaged 52 hr/well. Tiebacks for all three Casing strings averaged 90 hr for all surface and subsea operations including BOP test and nipple-up/nipple-down time. Metal sealing of the primary Casing Annulus has been made practical because the offshore industry has gone toward compact-wellheads and hanging of the completion on a mandrel. Hanging the completion on a mandrel, however, has it own set of considerations. Exact riser length may be difficult to predict before running because the riser must first be locked into the mudline Casing hanger and then landed out on the support shoulder in the surface head. Also, a general desire is that riser tieback strings should be in tension after installation. This is not always easy with a passive or dumb hanger and fixed should configuration. Threaded, adjustable mandrel hanger systems exist but can require verymore » close Casing string space-out to achieve the desired residual riser tension. The paper describes the objectives, forged sleeves, running sequence, cold forging, and the prototype test.« less

David Andrew Cuthill - One of the best experts on this subject based on the ideXlab platform.

  • A Case Study: Profiling Gas Production in the Tubing/Casing Annulus, Using Noise/Temperature Logging Techniques
    International Oil and Gas Conference and Exhibition in China, 2013
    Co-Authors: Mathieu M. Molenaar, Bryan Cowan, Erkan Fidan, David Andrew Cuthill
    Abstract:

    To reduce liquid loading on multizone unconventional gas wells, tubing can be run to a depth below the lowest perforation interval. Gas flows down the tubing/Casing Annulus and flows up the tubing, eliminating liquid buildup. For production surveillance, this wellbore configuration is not conducive to obtaining conventional production logs. Conventional production profiling techniques involve repositioning the tubing string or removing it altogether. If the tubing remains in place during logging, the costs associated with pulling the tubing are eliminated; production is not suspended; and the risks associated with well control are reduced. Also by not modifying the wellbore configuration, fluid velocities are not affected and the log results more closely represent the actual production profile. Ideally the well should be logged without manipulating the tubing to provide a representative production profile. Noise/temperature logging has been used for many years to assist in locating sources of fluid flow behind Casing. The use of this technique to obtain a pseudo or qualitative production-flow profile in the tubing/Casing Annulus was explored to enable the tubing to remain in the wellbore and obtain a measurement of the flow behind pipe. In the 1970s, tests where conducted to quantify wellbore inflow using noise logs. The research was recently used to evaluate numerous wells in western Canada with favorable results. This paper discusses the logging method and presents comparisons to profiling results from conventional production-logging techniques with emphasis on the cost savings to the operator. Introduction In general, tight-gas developments require a dense spacing of wells, ranging from a few to several wells per section. On these wells, regulators often require that a production-logging survey be acquired periodically. In Canada these requirements vary from province to province. Often, in the absence of regulatory requirements, operators must determine if the relative contribution of each completion zone continues to deliver gas as originally identified in logs. These tight-gas reservoirs are usually completed over several zones in stacked-pay, and each zone has varying subsurface qualifiers. These qualifiers can include different system permeability, stress distribution, and natural fractures—all tend to increase the delivery anisotropy between zones, especially when all zones are commingled. This anisotropy in producibility can create early water loading of some zones or even complete loss of production from zones within the first 3 months of a well being placed on production. It is critical to run a periodic flow profile that assists in predicting earlier-than-expected termination of the completed net pay. If remediation is required, corrective action could include refracturing, or if the well is liquid loading, then running a plunger or foam injection could be recommended. The water flowback during production usually becomes a hindrance to effective gas lift, forcing operators to run production tubing deep immediately from the onset of the production. Deep-run tubing, which is hung past the deepest set of perforations, can help lift the liquids and delay liquid loading in wellbore. Gas inflow is directed downward within the tubing/Casing Annulus, thereby lifting the liquid buildup from the wellbore as the gas is produced up the tubing. Normally monitoring is performed using downhole production-logging tools (PLT) to provide a production profile across the perforated intervals. These tools must be exposed to the wellbore and be run within the flowstream to measure fluid flow rates,

  • a case study profiling gas production in the tubing Casing Annulus using noise temperature logging techniques
    International Oil and Gas Conference and Exhibition in China, 2010
    Co-Authors: Mathieu M. Molenaar, Bryan Cowan, Erkan Fidan, David Andrew Cuthill
    Abstract:

    To reduce liquid loading on multizone unconventional gas wells, tubing can be run to a depth below the lowest perforation interval. Gas flows down the tubing/Casing Annulus and flows up the tubing, eliminating liquid buildup. For production surveillance, this wellbore configuration is not conducive to obtaining conventional production logs. Conventional production profiling techniques involve repositioning the tubing string or removing it altogether. If the tubing remains in place during logging, the costs associated with pulling the tubing are eliminated; production is not suspended; and the risks associated with well control are reduced. Also by not modifying the wellbore configuration, fluid velocities are not affected and the log results more closely represent the actual production profile. Ideally the well should be logged without manipulating the tubing to provide a representative production profile. Noise/temperature logging has been used for many years to assist in locating sources of fluid flow behind Casing. The use of this technique to obtain a pseudo or qualitative production-flow profile in the tubing/Casing Annulus was explored to enable the tubing to remain in the wellbore and obtain a measurement of the flow behind pipe. In the 1970s, tests where conducted to quantify wellbore inflow using noise logs. The research was recently used to evaluate numerous wells in western Canada with favorable results. This paper discusses the logging method and presents comparisons to profiling results from conventional production-logging techniques with emphasis on the cost savings to the operator. Introduction In general, tight-gas developments require a dense spacing of wells, ranging from a few to several wells per section. On these wells, regulators often require that a production-logging survey be acquired periodically. In Canada these requirements vary from province to province. Often, in the absence of regulatory requirements, operators must determine if the relative contribution of each completion zone continues to deliver gas as originally identified in logs. These tight-gas reservoirs are usually completed over several zones in stacked-pay, and each zone has varying subsurface qualifiers. These qualifiers can include different system permeability, stress distribution, and natural fractures—all tend to increase the delivery anisotropy between zones, especially when all zones are commingled. This anisotropy in producibility can create early water loading of some zones or even complete loss of production from zones within the first 3 months of a well being placed on production. It is critical to run a periodic flow profile that assists in predicting earlier-than-expected termination of the completed net pay. If remediation is required, corrective action could include refracturing, or if the well is liquid loading, then running a plunger or foam injection could be recommended. The water flowback during production usually becomes a hindrance to effective gas lift, forcing operators to run production tubing deep immediately from the onset of the production. Deep-run tubing, which is hung past the deepest set of perforations, can help lift the liquids and delay liquid loading in wellbore. Gas inflow is directed downward within the tubing/Casing Annulus, thereby lifting the liquid buildup from the wellbore as the gas is produced up the tubing. Normally monitoring is performed using downhole production-logging tools (PLT) to provide a production profile across the perforated intervals. These tools must be exposed to the wellbore and be run within the flowstream to measure fluid flow rates,

W.m. Taylor - One of the best experts on this subject based on the ideXlab platform.

  • Cold-forged connector ties back well risers in Congo field
    Oil & Gas Journal, 1997
    Co-Authors: W.m. Taylor, M. Tison, A. Bahoumina
    Abstract:

    The tieback of eleven 10 3/4-in., high-pressure risers in Elf Congo`s offshore N`Kossa field used a cold-forge tieback system to create a metal seal. The time-saving tieback method allows for placing the risers in residual tension. The installation work was completed in the fall of 1995. Average time to complete the 10 3/4-in. Casing tiebacks, including test and nipple-up and nipple-down times, averaged 52 hr/well. Tiebacks for all three Casing strings averaged 90 hr for all surface and subsea operations including BOP test and nipple-up/nipple-down time. Metal sealing of the primary Casing Annulus has been made practical because the offshore industry has gone toward compact-wellheads and hanging of the completion on a mandrel. Hanging the completion on a mandrel, however, has it own set of considerations. Exact riser length may be difficult to predict before running because the riser must first be locked into the mudline Casing hanger and then landed out on the support shoulder in the surface head. Also, a general desire is that riser tieback strings should be in tension after installation. This is not always easy with a passive or dumb hanger and fixed should configuration. Threaded, adjustable mandrel hanger systems exist but can require verymore » close Casing string space-out to achieve the desired residual riser tension. The paper describes the objectives, forged sleeves, running sequence, cold forging, and the prototype test.« less

  • Cold-forged connector ties back well risers in Congo field
    Oil & Gas Journal, 1997
    Co-Authors: W.m. Taylor, M. Tison, A. Bahoumina
    Abstract:

    The tieback of eleven 10 3/4-in., high-pressure risers in Elf Congo`s offshore N`Kossa field used a cold-forge tieback system to create a metal seal. The time-saving tieback method allows for placing the risers in residual tension. The installation work was completed in the fall of 1995. Average time to complete the 10 3/4-in. Casing tiebacks, including test and nipple-up and nipple-down times, averaged 52 hr/well. Tiebacks for all three Casing strings averaged 90 hr for all surface and subsea operations including BOP test and nipple-up/nipple-down time. Metal sealing of the primary Casing Annulus has been made practical because the offshore industry has gone toward compact-wellheads and hanging of the completion on a mandrel. Hanging the completion on a mandrel, however, has it own set of considerations. Exact riser length may be difficult to predict before running because the riser must first be locked into the mudline Casing hanger and then landed out on the support shoulder in the surface head. Also, a general desire is that riser tieback strings should be in tension after installation. This is not always easy with a passive or dumb hanger and fixed should configuration. Threaded, adjustable mandrel hanger systems exist but can require verymore » close Casing string space-out to achieve the desired residual riser tension. The paper describes the objectives, forged sleeves, running sequence, cold forging, and the prototype test.« less

Bin Zhao - One of the best experts on this subject based on the ideXlab platform.

  • Failure Analysis on the Collapsed Tubing of High Pressure and High Production Gas Well in the Process of Testing and Production
    2016
    Co-Authors: Ji-jun Xue, Bin Zhao, He Zhao
    Abstract:

    Abstract. The split, fall, collapse and severe diapirism of tube body happened on one of the tubing used in the gas well of high pressure and high production in the process of the trial extraction. This paper aims to explore the reason of its occurrence through the research of the macroscopic analysis, mechanical and chemical property test and microscopic metallographic test study. The result of the research shows that the multiphase flow of gas, liquid and solid in the tubing may produced an instantaneous negative pressure and increased the possibility of the tubing being collapsed in the process of gas testing and production.Then it resulted in clogging, severe ablation, thinning wall and piercing in tube and finally the tube broke because of the low tensile strength. General The gas well have a depth of 4384.33m, the calculating gas production is 13. 6231 x 104m3/d and the pressure of hole bottom is high. So it’s a high voltage and high production gas well. When the water pressure is 70 Mpa as the blowout preventer is closed and seals on Casing Annulus pressure compressed after setting the downhole packer, the pressure test is qualified. For slurry process, ignition success after reverse circulation washing well, Annulus have a high-pressure of 49 Mpa after washing the well. During the trying production of the gas well, no liquid flows out, the flame is a

Mathieu M. Molenaar - One of the best experts on this subject based on the ideXlab platform.

  • A Case Study: Profiling Gas Production in the Tubing/Casing Annulus, Using Noise/Temperature Logging Techniques
    International Oil and Gas Conference and Exhibition in China, 2013
    Co-Authors: Mathieu M. Molenaar, Bryan Cowan, Erkan Fidan, David Andrew Cuthill
    Abstract:

    To reduce liquid loading on multizone unconventional gas wells, tubing can be run to a depth below the lowest perforation interval. Gas flows down the tubing/Casing Annulus and flows up the tubing, eliminating liquid buildup. For production surveillance, this wellbore configuration is not conducive to obtaining conventional production logs. Conventional production profiling techniques involve repositioning the tubing string or removing it altogether. If the tubing remains in place during logging, the costs associated with pulling the tubing are eliminated; production is not suspended; and the risks associated with well control are reduced. Also by not modifying the wellbore configuration, fluid velocities are not affected and the log results more closely represent the actual production profile. Ideally the well should be logged without manipulating the tubing to provide a representative production profile. Noise/temperature logging has been used for many years to assist in locating sources of fluid flow behind Casing. The use of this technique to obtain a pseudo or qualitative production-flow profile in the tubing/Casing Annulus was explored to enable the tubing to remain in the wellbore and obtain a measurement of the flow behind pipe. In the 1970s, tests where conducted to quantify wellbore inflow using noise logs. The research was recently used to evaluate numerous wells in western Canada with favorable results. This paper discusses the logging method and presents comparisons to profiling results from conventional production-logging techniques with emphasis on the cost savings to the operator. Introduction In general, tight-gas developments require a dense spacing of wells, ranging from a few to several wells per section. On these wells, regulators often require that a production-logging survey be acquired periodically. In Canada these requirements vary from province to province. Often, in the absence of regulatory requirements, operators must determine if the relative contribution of each completion zone continues to deliver gas as originally identified in logs. These tight-gas reservoirs are usually completed over several zones in stacked-pay, and each zone has varying subsurface qualifiers. These qualifiers can include different system permeability, stress distribution, and natural fractures—all tend to increase the delivery anisotropy between zones, especially when all zones are commingled. This anisotropy in producibility can create early water loading of some zones or even complete loss of production from zones within the first 3 months of a well being placed on production. It is critical to run a periodic flow profile that assists in predicting earlier-than-expected termination of the completed net pay. If remediation is required, corrective action could include refracturing, or if the well is liquid loading, then running a plunger or foam injection could be recommended. The water flowback during production usually becomes a hindrance to effective gas lift, forcing operators to run production tubing deep immediately from the onset of the production. Deep-run tubing, which is hung past the deepest set of perforations, can help lift the liquids and delay liquid loading in wellbore. Gas inflow is directed downward within the tubing/Casing Annulus, thereby lifting the liquid buildup from the wellbore as the gas is produced up the tubing. Normally monitoring is performed using downhole production-logging tools (PLT) to provide a production profile across the perforated intervals. These tools must be exposed to the wellbore and be run within the flowstream to measure fluid flow rates,

  • a case study profiling gas production in the tubing Casing Annulus using noise temperature logging techniques
    International Oil and Gas Conference and Exhibition in China, 2010
    Co-Authors: Mathieu M. Molenaar, Bryan Cowan, Erkan Fidan, David Andrew Cuthill
    Abstract:

    To reduce liquid loading on multizone unconventional gas wells, tubing can be run to a depth below the lowest perforation interval. Gas flows down the tubing/Casing Annulus and flows up the tubing, eliminating liquid buildup. For production surveillance, this wellbore configuration is not conducive to obtaining conventional production logs. Conventional production profiling techniques involve repositioning the tubing string or removing it altogether. If the tubing remains in place during logging, the costs associated with pulling the tubing are eliminated; production is not suspended; and the risks associated with well control are reduced. Also by not modifying the wellbore configuration, fluid velocities are not affected and the log results more closely represent the actual production profile. Ideally the well should be logged without manipulating the tubing to provide a representative production profile. Noise/temperature logging has been used for many years to assist in locating sources of fluid flow behind Casing. The use of this technique to obtain a pseudo or qualitative production-flow profile in the tubing/Casing Annulus was explored to enable the tubing to remain in the wellbore and obtain a measurement of the flow behind pipe. In the 1970s, tests where conducted to quantify wellbore inflow using noise logs. The research was recently used to evaluate numerous wells in western Canada with favorable results. This paper discusses the logging method and presents comparisons to profiling results from conventional production-logging techniques with emphasis on the cost savings to the operator. Introduction In general, tight-gas developments require a dense spacing of wells, ranging from a few to several wells per section. On these wells, regulators often require that a production-logging survey be acquired periodically. In Canada these requirements vary from province to province. Often, in the absence of regulatory requirements, operators must determine if the relative contribution of each completion zone continues to deliver gas as originally identified in logs. These tight-gas reservoirs are usually completed over several zones in stacked-pay, and each zone has varying subsurface qualifiers. These qualifiers can include different system permeability, stress distribution, and natural fractures—all tend to increase the delivery anisotropy between zones, especially when all zones are commingled. This anisotropy in producibility can create early water loading of some zones or even complete loss of production from zones within the first 3 months of a well being placed on production. It is critical to run a periodic flow profile that assists in predicting earlier-than-expected termination of the completed net pay. If remediation is required, corrective action could include refracturing, or if the well is liquid loading, then running a plunger or foam injection could be recommended. The water flowback during production usually becomes a hindrance to effective gas lift, forcing operators to run production tubing deep immediately from the onset of the production. Deep-run tubing, which is hung past the deepest set of perforations, can help lift the liquids and delay liquid loading in wellbore. Gas inflow is directed downward within the tubing/Casing Annulus, thereby lifting the liquid buildup from the wellbore as the gas is produced up the tubing. Normally monitoring is performed using downhole production-logging tools (PLT) to provide a production profile across the perforated intervals. These tools must be exposed to the wellbore and be run within the flowstream to measure fluid flow rates,