Detecting Water Influx in Beam Pump Lifted Horizontal Wells in a South Oman Field Uing Temperature Measurements, Production Profiling, and Concentric Coiled Tubing
Abstract: fax 01-972-952-9435.This paper will present case histories of the profiling technique along with results and conclusions. It will also compare the response from this technique to normal production logging.
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Petroleum Development Oman (PDO) is producing substantial amounts of unwanted water or gas from most of its oil fields. To increase recovery from maturing reservoirs, PDO is developing the capability to detect and shut-off unwanted water and gas. Swelling elastomers have been deployed to segment horizontal wells in combination with surveillance and shut-off technologies. In beam pump wells dual wellheads have enabled logging while pumping. A key element to achieve improved oil recovery through well and reservoir management in a horizontal well is segmenting the well into different flow units. Swelling Elastomers (SE) are being deployed to enable segmentation. SE tool provides zonal isolation through the swelling of the elastomers when contacting produced water in the wellbore. In clastic reservoirs the completion philosophy has been changed from drilling minimum functionality wells to wells with closed-annulus completions that allow for surveillance and interventions. Surveillance is done in the drilling phase with under-balanced drilling and other open hole logging measurements. In the work over phase unwanted flow segments have been detected by logging while pumping coupled with greater integration of available reservoir data. Mechanical segment shut-off methods have been used. To date PDO has segmented more than 100 horizontal wells with swelling elastomers. In more than 20 wells suspected water producing feature were isolated at the initial completion stage and the rest were segmented based on reservoir flow unit characterization. After having proved that SE is delivering value in initial water shut off, the strategy is to prove a viable surveillance technique to identify water entry point in horizontal wells, and to develop several reliable water shut off (WSO) techniques depending on which segment's to be closed and if reversibility is required. To date more than one million barrels of oil have been realized as a result of the initial isolations as well as subsequent water shut offs. This paper is a continuation to the work presented in SPE paper number 91665 and will present case histories of the delivery and management of wells with swelling elastomer in clastic reservoirs in Oman. Introduction The South fields are located in southern Oman is in fact a group of six fields. Most of them are mature oil fields operated by Petroleum Development Oman. The fields produce medium gravity viscous crude with viscosity ranging from 200–550 cp. Reservoir pressure is maintained by infinite bottom water drive. The fields have been producing since mid 1980's. Initial fields' development was via vertical wells however, since the mid 1990's development has been primarily with horizontal wells. Production is from a combination of Aeolian and glacial sediments. Reservoir heterogeneity is high especially in the glacial Alkhalata reservoir. These fields accounts for more than 10% of total PDO production and is produced from almost 500 active wells. The current field water cut is about 93%. South field wells have different design. Almost all South field wells must have sand control. The horizontal reservoir section is about 350–500m long. The horizontal section may cross both reservoirs (Alkhalata and Aeolian Amin reservoirs). The horizontal section is drilled with a 61/8" drill bit and completed with stand-alone 4½" sand control liner using 200 micron wire-wrap screens (WWS) in open hole. This results in an open annulus between the sand control liner and the formation. More than 90% of well are artificially lifted via beam pump (BP) hence hindering accessibility due to surface units and rods. In the early development phases it was assumed that water production is simply a result of conning, and water is produced through matrix and all faults fractures are assumed to be sealing. However since the start of infill drilling in 1999, the new oil production has been historically dominated by high initial BSW levels and as of 2002 new wells produced cumulative average of three barrels of water for every one barrel of oil during their first year of production.
Petroleum Development Oman (PDO) is producing substantial amounts of unwanted water or gas from most of its oil fields. To increase recovery from maturing reservoirs, PDO is developing the capability to detect and shut-off unwanted water and gas. Swelling elastomers have been deployed to segment horizontal wells in combination with surveillance and shut-off technologies. In beam pump wells dual wellheads have enabled logging while pumping. A key element to achieve improved oil recovery through well and reservoir management in a horizontal well is segmenting the well into different flow units. Swelling Elastomers (SE) are being deployed to enable segmentation. SE tool provides zonal isolation through the swelling of the elastomers when contacting produced water in the wellbore. In clastic reservoirs the completion philosophy has been changed from drilling minimum functionality wells to wells with closed-annulus completions that allow for surveillance and interventions. Surveillance is done in the drilling phase with under-balanced drilling and other open hole logging measurements. In the work over phase unwanted flow segments have been detected by logging while pumping coupled with greater integration of available reservoir data. Mechanical segment shut-off methods have been used. To date PDO has segmented more than 100 horizontal wells with swelling elastomers. In more than 20 wells suspected water producing feature were isolated at the initial completion stage and the rest were segmented based on reservoir flow unit characterization. After having proved that SE is delivering value in initial water shut off, the strategy is to prove a viable surveillance technique to identify water entry point in horizontal wells, and to develop several reliable water shut off (WSO) techniques depending on which segment's to be closed and if reversibility is required. To date more than one million barrels of oil have been realized as a result of the initial isolations as well as subsequent water shut offs. This paper is a continuation to the work presented in SPE paper number 91665 and will present case histories of the delivery and management of wells with swelling elastomer in clastic reservoirs in Oman. Introduction The South fields are located in southern Oman is in fact a group of six fields. Most of them are mature oil fields operated by Petroleum Development Oman. The fields produce medium gravity viscous crude with viscosity ranging from 200–550 cp. Reservoir pressure is maintained by infinite bottom water drive. The fields have been producing since mid 1980's. Initial fields' development was via vertical wells however, since the mid 1990's development has been primarily with horizontal wells. Production is from a combination of Aeolian and glacial sediments. Reservoir heterogeneity is high especially in the glacial Alkhalata reservoir. These fields accounts for more than 10% of total PDO production and is produced from almost 500 active wells. The current field water cut is about 93%. South field wells have different design. Almost all South field wells must have sand control. The horizontal reservoir section is about 350–500m long. The horizontal section may cross both reservoirs (Alkhalata and Aeolian Amin reservoirs). The horizontal section is drilled with a 61/8" drill bit and completed with stand-alone 4½" sand control liner using 200 micron wire-wrap screens (WWS) in open hole. This results in an open annulus between the sand control liner and the formation. More than 90% of well are artificially lifted via beam pump (BP) hence hindering accessibility due to surface units and rods. In the early development phases it was assumed that water production is simply a result of conning, and water is produced through matrix and all faults fractures are assumed to be sealing. However since the start of infill drilling in 1999, the new oil production has been historically dominated by high initial BSW levels and as of 2002 new wells produced cumulative average of three barrels of water for every one barrel of oil during their first year of production.
Sand/Well Vacuuming Technology with Concentric Coiled Tubing: Best Practices and Lessons Learned from Over 600 Operations
Sand production is a common problem with unconsolidated formations. It is very challenging to successfully remove formation sands with conventional methods in a large deviated wellbore with a low pressure gradient formation 1. Since 1995, a technology combining concentric coiled tubing (CCT) with a jet pump has been developed and used to remove both the drilling fluids and solids. Initially it was developed for horizontal heavy oil reservoirs where pressures are low and viscosity is high, without placing hydrostatic loads on the reservoir. The job data from more than 600 sand/well vacuuming operations worldwide has been compiled into a database. This paper reviews the well information and the key operating parameters: maximum depth, bottom hole pressure gradient and pump rate. The engineering challenges, best practices and lessons learned for the sand/well vacuuming process are also summarized. Analysis of this data yields a better understanding about this vacuuming technology and provides good guideline for future practice. Case histories are provided which demonstrate how to deploy the different sand/well vacuuming bottom hole assemblies (BHA), to; increase the penetration capacity with a jetting tool; entering multi-laterals with an entry guidance system; accessing small size holes with a micro-vacuuming tool; and to achieve extended reach under extreme conditions. Post job analysis indicates CCT vacuuming technology reduces the skin damage and increases the production compared to non-vacuumed wells. Moreover, the details from sand and other fluid influx profiles obtained along the wellbore based on the analysis of the returns during the vacuuming process, could be used to evaluate well production and assist in formulating a management strategy. Introduction During the drilling of most horizontal heavy oil wells, the drilling fluid's hydrostatic column produces fluid losses to the formation due to the low bottom hole pressure (BHP). Otherwise, the presence of a filter cake adhered creates an artificial layer between the formation face and the outer part of the slotted liner, affecting the pressure transference from the reservoir, in other words, creating an additional pressure drop from the formation to the wellbore. After the drilling operation is completed, the production pump is run in the hole and is used to retrieve the drilling fluids and the filter cake remaining in the well. The problem with this method is that the suction produced by the production pump is mainly in the nearest zones to the pump and does not create significant suction in the toe of the horizontal section. Therefore, the well will produce predominantly from the heel and have less production from the toe. Sand production is also a common problem faced by many of the heavy oil producers worldwide. A slotted liner acts as a partial barrier, grading effects at the slots often still result in sand migration into the wellbore and, hence, a lower production rate. The low production flow rates contribute to increased deposition of the sand in the highly deviated wellbore. Several cleanout options have been developed over the decades, employing a number of different techniques and approaches 1. However, coiled tubing (CT) or conventional jointed pipe often incorporate the need for high circulation rates, special fluids or reverse circulation methods to remove the solids. With high rates and high specific gravity water based fluids, conventional sand cleanout methods often apply an excess pressure on the formation and this results in lost circulation returns to the low formation pressure reservoirs. A typical reservoir pressure in these wells may be as low as 0.04 psi/ft. This makes sand removal virtually impossible and creating damage to the formation likely. Nitrogen can be used to reduce hydrostatic pressure, but this necessitates a very specific job design and execution and can require large quantities of liquid nitrogen in the case of horizontal wells located in some remote area.
Sand or Mud Removal in Low Bottom Hole Pressure Wellbores Using Jet Pump and Concentric Coiled Tubing Leads to Improved Production
Horizontal drilling and completion are common practice for accessing conventional and heavy oil reservoirs. During the drilling process, the formation pore pressure is less than the drilling fluid's hydrostatic pressure. This can lead to some fluid loss before a filter cake is formed to prevent further mud losses. For unconsolidated formations, it is prefer to keep the filter cake in the place to maintain the hole's integrity during the well completion period while running the liner. However, the filter cake can be broken down by the sliding and rotating of the bottom hole assembly. These breakdowns can lead to high completion fluid losses to the formation. Sand production is also a common problem associated with unconsolidated formations. These drilling & completion practices, sand production, have resulted in a demand for well intervention that can economically remove mud damage and produced fill throughout the whole length of horizontal wells. Since 1995, a technology combining concentric coiled tubing (CCT) with a jet pump has been developed and used to remove both the drilling fluids, filter cake and solids. Initially it was developed for horizontal heavy oil reservoirs where pressures are low and oil viscosity is high, without placing hydrostatic loads on the reservoir. The job data from more than 600 sand/well vacuuming operations worldwide has been compiled into a database. This paper reviews the well information and the key operating parameters: maximum depth, bottom hole pressure gradient and pump rate. The engineering challenges, best practices and lessons learned from the sand/well vacuuming process are also summarized. Analysis of this data yields a better understanding about the vacuuming technology and provides good guideline for future operations. Case histories are provided demonstrating how to deploy the different sand/well vacuuming bottom hole assemblies (BHA) for different applications. Post job analysis indicates CCT vacuuming technology reduces the skin damage and increases the production compared to non-vacuumed wells. Moreover, the details estimated from sand and other fluid influx profiles along the wellbore during the vacuuming process, are used to evaluate well production and develop a management strategy. Introduction During the drilling operation of most horizontal heavy oil wells, the drilling fluid hydrostatic column causes fluid loss to the formation due to the low bottom hole pressure (BHP). Otherwise, the presence of the filter cake adhered to the formation face creates an artificial layer between the formation face and the slotted liner, affecting the production from the reservoir, in other words, creating an additional pressure drop from the formation to the wellbore. After the drilling operation is completed, the production pump is run in hole and used to retrieve drilling fluids and the filter cake. The problem with this method is that the suction produced by the production pump is mainly a localised pressure drop in the zones nearest to the pump, without creating significant suction at the toe of the well. Therefore, the well will produce mainly from the heel and will have a lower production contribution from the toe. Sand production is also a common problem faced by many of heavy oil producers worldwide. The slotted liner acts as a partial barrier, grading effects at the slots often still result in sand migration into the wellbore and a low production rate. The low production flow rates contribute to increased deposition of the sand within the highly deviated wellbore.
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