• Xưởng sửa chữa và chuẩn chỉnh máy địa vật lý

    Xưởng có nhiệm vụ chính là bảo dưỡng, sửa chữa và hiệu chỉnh các máy móc thiết bị điện tử phục vụ cho các đơn vị trong Xí nghiệp địa vật lý giếng khoan. Ngoài ra xưởng còn nghiên cứu đưa vào ứng dụng và phát triển công nghệ tin học trong công tác địa vật lý

  • Trung tâm Phân tích và Xử lý số liệu

    Có nhiệm vụ đánh giá chất lượng tài liệu do Xí nghiệp Địa vật lý thực hiện.

  • Đội công nghệ cao

    Khảo sát địa vật lý tổng hợp trong giếng đang khoan. Đo địa vật lý tổng hợp, bắn mìn.

  • Đội Kiểm tra công nghệ khai thác

    Có nhiệm vụ là đo khảo sát và kiểm tra công nghệ khai thác trong các giếng khai thác và bơm ép.

  • Đội Carota khí

    Đội Carôta khí có nhiệm vụ chính là khảo sát carota khí, cung cấp kịp thời các số liệu để xác minh trữ lượng, tình trạng các giếng khoan.

  • Đội thử vỉa

    Đội có nhiệm vụ thử vỉa ở các giếng khoan nhằm định hướng cho công tác khoan, xác định tình trạng và đo vỉa, cung cấp thông tin để xác định trữ lượng công nghiệp của giếng

L&TD

LOGGING & TESTING DIVISION

XÍ NGHIỆP ĐỊA VẬT LÝ GIẾNG KHOAN - BẠN ĐỒNG HÀNH CỦA CÁC NHÀ DẦU KHÍ

Sản phẩm dịch vụ

LPR-N™ Tester Valve

LPR-N™ Tester Valve

The LPR-N™ tester valve is a full-opening, annulus pressure-operated valve. It measures multiple closed-in pressures in cased holes where pipe manipulation is restricted and a full-opening string is required. The nitrogen chamber is charged at the surface to a selected pressure determined by surface temperature, bottomhole temperature, and bottomhole pressure. If the intended test requires a permanent packer that uses a stinger mandrel or seal nipple, a variety of Halliburton bypass tools are available, depending on field application, to help ensure that the formations and downhole equipment are protected from excessive pressure buildup.

Features and Benefits

•  The ball valve operates independently of internal pressure

changes, such as with acidizing or fracturing operations.

•  Advanced materials and processes provide a unique metal-to-metal seat for exceptional gas-holding capabilities. 

•  The LPR-N tester valve has been through an extensive five-day qualification testing at 400°F and 15,000 psi burst and collapse pressures.

•  An open-in feature allows the operator to run the LPR-N tester in the hole with the ball valve opened or closed.

•  Fluids can be spotted or circulated through the LPR-N tester with the packer unseated.A double nitrogen chamber can be

added to the LPR-N tester for use in deep, hot, high-pressure wells to reduce the operating pressure.

Operation

The LPR-N tester valve is composed of a ball valve section, a power section, and a metering section. The ball valve section provides multiple downhole closures. It is turned by operating arms. The power section has a floating piston that is exposed to the hydrostatic pressure on one side and pressurized nitrogen on the other side. With the packer set, pump pressure applied to the annulus moves the piston downward, activates the operating arms, and opens the ball valve. When the annulus pressure is released, pressurized nitrogen returns the piston upward, closing the ball.After the surface equipment is properly installed, the packer is set, and the rams are closed, pressure is applied to the annulus, using rig pumps to operate the LPR-N tester.

          To begin testing, quickly apply pump pressure to the annulus to a predetermined pressure, and hold for 10 minutes to pressurize the nitrogen chamber. After pressure has been metered through the metering cartridge, pressure in the nitrogen chamber will be slightly less than combined hydrostatic and pump pressure in the annulus. This helps ensure that the ball valve stays open during testing or treating operations. The closing force may be increased on wells with an extremely high flow rate and wells producing a large amount of sand. Before the tool is closed, the annulus pressure is increased to a predetermined safe pressure below the operating pressure of the circulating valve and held for 10 minutes. This procedure creates additional closing force when the annulus pressure is released. Releasing the annulus pressure as quickly as possible closes the ball valve. A minimum of 10 minutes is needed to allow excess closing pressure in the nitrogen chamber to equalize before annulus pressure is reapplied. It is best to use the highest safe operating pressure to obtain maximum closing force.

LPR-NTM Tester Valve

Nominal ToolSize (in)
OD in.(cm) ID In.(cm) Thread connnections Length in.(cm) Stroke Length in. (cm) Tensile Rating** lb (kg) Working Pressure*** psi(bar)  
5.00 SG 5.03  (12.78)   2.28 (5.79)   3 7/8 CAS 208.46 (529.49)   60.00 (152.4)   405,581   (183 971)  

  15,000               (1034)  

Meets NACE-0175  > 175°F (79°C) standards for H2S service

*Service temperature up to 450°F (dressed with 600 series o-rings and PEEK™ back-up seals)

**The values of tensile, burst, and collapse strength are calculated with new tool conditions, Lame’s formula for burst and collapse strength, and stress

area calculations for tensile strength.

***Pressure rating is defined as differential pressure at the tool. (Differential pressure is the difference in pressure between the casing annulus tool ID.)

These ratings are guidelines only. For more information, contact your local Halliburton representative.

PEEK is a trademark of ICI Americas, Inc. Poly-Ether-Ether-Ketone.

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Dual Latelog

In order to use the latest techniques in wireline logging and for more effective analysis in sedimentary and basement rock, from 1997 Vietsovpetro Logging & Testing division has been using Halliburton’s Dual Laterolog Tools (DLL-T).

Dual Laterolog service provides reliable means of measuring formation resistivity in conductive borehole fluids under harsh downhole conditions. Accurate resistivity measurements are critical for

  • Accurately computing hydrocarbon saturation
  • Delineating thin beds
  • Indicating permeable zones and estimating invasion diameter (when used with an appropriate Rxo measurement)
  • Identifying formation fluid contacts within the reservoir
  • Acquiring optimum formation resistivity measurements when the contrast between formation resistivity and borehole-fluid resistivity is very high
  • Indicating fracture zones in both sedimentary and basement rock

Tool Specification
  Deep Laterolog Shallow Laterolog
 Max Temp 350°F (175°C)
 Max press
20 000 psi (137900 kPa)
 Max hole 24 in (610 mm)
 Min hole 4.5 in (115 mm)
 Max hole 24 in (610 mm)
Vertical Resolution 24 in. (61.0 cm) 24 in. (61.0 cm)
Depth of Investigation (50%) 60 - 84 in(154.2 - 213.4 cm 24 - 36 in (61.0 - 91.4 cm)
Sensitivity
1% of reading
1% of reading
Accuracy, High
5%
 5%
Accuracy, Low
5 %
5 %
Primary Curves LLD LLS
Secondary Curve 
LS
 

Benefits and Features

  • Consistent, high-quality measurements

The tool is calibrated with an advanced calibration system.

  • Accurate deep (LLd) and shallow (LLs) formation resistivity measurements

The tool employs dual electrode arrays and an automatic current-focusing technique.

  • Reliable performance, even under harsh well conditions

Rugged construction and quality electronics help ensure that the tool functions properly at elevated temperatures and pressures.

 
  • Single-pass, comprehensive formation evaluation

The DLL tool is combinable with a complete family of tools that operates under Halliburton’s Digital Interactive Telemetry System.

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OMNI™ Circulating Valve

OMNI™ Circulating Valve

The OMNI™ circulating valve is an annulus pressure-operated, recloseable circulating valve. Throughout the operation, the tool is repeatedly cycled up to a predetermined annulus pressure and then released.

The OMNI valve consists of a nitrogen section, an oil system, a circulating valve, and a ball valve. The nitrogen section contains the nitrogen gas that counterbalances the hydrostatic and annulus pressures. The amount of nitrogen in the tool depends on well hydrostatic (mud weight and depth) and downhole temperature. This information must be known to properly prepare the tool for running in.

Note: With certain completion fluids, the mud weight at the surface can be significantly different from the actual mud weight downhole.

The operating and control mechanisms are contained in a closed oil system activated by annulus pressure acting on the nitrogen chamber, allowing an unlimited number of pressure cycles.The circulating valve and the ball valve work together to keep circulating pressure off the formation. The ball valve will close before the circulating valve opens. The ball valve closes off the workstring.

Features and Benefits

•  Permits well testing, pressure testing, and fluid circulation

•  Allows unlimited number of pressure cycles

 

 

Operation

The well can be flow tested when the valve is in the well test position. When in this position, the circulating ports are closed and the ball valve is opened. During a downhole closure drillstem test, the OMNI valve is in the well test position during flow and shut-in periods. The workstring can be pressure-tested in the blank position because the ball valve closes before the circulating valve opens. Fluid can be pumped in either direction through the tool in the circulating position. In this position, the circulating ports are open and the ball valve is closed.Note: Before the tool is run, the hydrostatic pressure at the specified tool depth must be known. This information is required to obtain the proper nitrogen charging pressure.

OMNITM Circulating Valve

Nominal Tool Size (in) OD In.(cm) ID In.(cm) Thread connnections Services Temprature* oF (oC) Length In.(cm) Tensile Rating** Lb (kg) Working Pressure*** Psi(bar) Flowarea In2(cm2) Number Of Ports
5.00 SG1 5.03 (12.78) 2.28 (5.79) 3 7/8 CAS 450 (232)  68.02 (172.77) 450.000 (183.08)

    15.000       (1034)

  3.14    (20.26)   4

Meets NACE-0175 175°F (79°C) standards for H2S service

*Service temperature up to 450°F (dressed with 600 series o-rings and PEEK™ back-up seals)

**The values of tensile, burst, and collapse strength are calculated with new tool conditions, Lame’s formula for burst and collapse strength, and stress

area calculations for tensile strength.

***Pressure rating is defined as differential pressure at the tool. (Differential pressure is the difference in pressure between the casing annulus tool ID.)

These ratings are guidelines only. For more information, contact your local Halliburton representative.

PEEK is a trademark of ICI Americas, Inc. Poly-Ether-Ether-Ketone.

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Open hole logging

    1. INTRODUCTIONS

       Services

  • Electrical logs: DLL, MSFL, HRI, Dipmeter, EMI.
  • Radioactive logs: LDL, CNL, SGR, GR.
  •  Acoustic logs: BHC, FWSL, Crossed dipole wavesonic log, Bore hole televiewer, Vertical seismic profile. 
  • Others: Caliper, Deviation survey…
  • Toolpusher
  •  VSP (Vertical Seismic Profile)  

Read more ...

Instream Gauge Carrier

Instream Gauge Carrier  

         Instream gauge carriers carry as many as four pressure or temperature gauges in the flow stream to monitor downhole conditions while maintaining a full opening through the tools. The carriers are designed to carry 1.25-in. (31.75-mm) diameter electronic or mechanical gauges. Recorders are suspended on the inside of the running case, which has cushioning devices to protect the gauges from shock.

Features and Benefits

•  Permits unrestricted flow through the tools

•  Allows wireline operations to be run

•  Facilitates a faster response to temperature changes

 

 

 

 

 

Instream Gauge Carrier

Nominal Tool Size (in) OD In.(cm) ID In.(cm) Thread connnections Services Temprature* oF (oC) Length In.(cm) Tensile Rating** Lb (kg) Working Pressure*** Psi(bar) Flowarea In2(cm2) Number Of Ports
5.00 SG1 5.03 (12.78) 10.75 (21.31)

2.28

(5.79)

3 7/8 CAS

 450   204

68.02 (172.77 450.000 (183.08) 15.000 (1034) 4

Meets NACE-0175 175°F (79°C) standards for H2S service

*Service temperature up to 450°F (dressed with 600 series o-rings and PEEK™ back-up seals)

**The values of tensile, burst, and collapse strength are calculated with new tool conditions, Lame’s formula for burst and collapse strength, and stress

area calculations for tensile strength.

***Pressure rating is defined as differential pressure at the tool. (Differential pressure is the difference in pressure between the casing annulus tool ID.)

These ratings are guidelines only. For more information, contact your local Halliburton representative.

PEEK is a trademark of ICI Americas, Inc. Poly-Ether-Ether-Ketone.

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Surface Logging System & Excell 2000 Application

Time spent at the wellsite is a valuable commodity. How this time is utilized is even more important. If time is not taken to properly analyse and study all available data, decisions that can adversely affect future production of your well or field might be made. Conversely, if too much time is spent at the wellsite, delays in the well program can occur. It all relates back to one thing.

Read more ...

Drain Valve

Drain Valve

The drain valve consists of a ported body, sliding sleeve, and rotating nut, which contr ols the  position of the sliding sleeve. The sleeve either covers or exposes the ports in the body of the valve. The drain valve is suitable for sour service at all temperatures. A drain collar and associated components are required when relieving pressure.

Features and Benefits

•  Allows pressure trapped between two closed valves to be relieved in a controlled manner

•  Used to recover large volume fluid samples

Operation

The drain valve is installed between any two valves that may come out of the hole with pressure or fluid trapped between them. Pressure is relieved by installing the drain collar and drain nipples on the drain valve. Valves, lines, or sample bottles may be attached to the drain nipples depending on the desired disposition of the fluid in the string. After the drain collar assembly is attached, the ports in the tool are exposed by using a chain wrench or pipe wrench to rotate the

drain nut, which moves the sliding sleeve.When the ports in the sleeve are aligned with the ports in the body of the tool, the fluid may be drained.It is also possible to trap a large volume fluid sample between two valves if a sample chamber of some kind (tubing, drill

collar, etc.) is placed between the valves. In most cases, the drain valve would be run at the bottom of the sample chamber to facilitate transfer. This will not be a PVT sample.

 

 

Drain Valve
Nominal Tool Size (in) OD In. (cm) ID In. (cm) Services Temprature* oF (oC) Length In. (cm) Tensile Rating**  Lb (kg) Working Pressure*** Psi (bar) Flowarea In2(cm2) Number Of Ports
5.00       SG1 5.03 (12.78) 2.28 (5.79) 3 7/8 CAS 450

(232)

 68.02 

(172.77)

450.000 (183.08)     15.00  (1034)   3.14  (20.26)   4

Meets NACE-0175 175°F (79°C) standards for H2S service

*Service temperature up to 450°F (dressed with 600 series o-rings and PEEK™ back-up seals)

**The values of tensile, burst, and collapse strength are calculated with new tool conditions, Lame’s formula for burst and collapse strength, and stress

area calculations for tensile strength.

***Pressure rating is defined as differential pressure at the tool. (Differential pressure is the difference in pressure between the casing annulus tool ID.)

These ratings are guidelines only. For more information, contact your local Halliburton representative.

PEEK is  trademark of ICI Americas, Inc. Poly-Ether-Ether-Ketone.

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Rupture Disk Safety Circulating Valve

Rupture Disk  Safety Circulating Valve

The rupture disk (RD) safety circulating valve functions as both a safety valve and circulating valve. The tool functions as a safety valve when the annulus pressure reaches a predetermined value. At that pressure, the  valve isolates the workstring below the tool and establishes communication between the annulus and the workstring above the tool. This tool converts into a circulating valve when the ball valve section is removed. 

Features and Benefits

The tool is composed of three major sections:

• The power section consists of a power mandrel case and rupture disk that is available for a wide range of pressure applications. The rupture disk bursts at a predetermined pressure, allowing annulus pressure to be applied to a differential area on the power mandrel. The power mandrel 

moves down, first pushing the ball valve closed, and then opening a set of circulating ports.

• The circulating section consists of a set of ports that are initially sealed by the power mandrel. When the rupture disk bursts, the power mandrel moves down, exposing the ports that allow communication between the annulus and workstring.

• The safety valve consists of a ball valve, operating pins, and collet fingers. As the power mandrel moves down, the operating arms close the ball valve. The collet fingers expand, allowing the power mandrel to continue traveling down to open the circulating ports.

Operation

Before the RD safety circulating valve is used, the operating pressure is calculated for selecting the proper rupture disk pressure rating. Required information includes mud weight, testing depth, bottomhole temperature, and maximum annulus pressure. When the rupture disk safety circulating valve is run with an annulus pressure-operated valve, the safety valve operating pressure should be kept 1,000 psi above the operating pressure of the tester valve.


Ruptute Disk (RD) Safety Curulating Valve

Nominal Tool Size (in) OD In.(cm) ID In.(cm) Thread connnections Services Temprature* oF (oC) Length In.(cm) Tensile Rating** Lb (kg) Working Pressure*** Psi(bar) Flowarea In2(cm2) Number Of Ports
5.00 SG1

5.03

(12.78)

10.75 (21.31) 2.28 (5.79) 3 7/8 CAS

 450   204

68.02 (172.77) 450.000 (183.08) 15.000 (1034) 4

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Slip Joints

IV. DOWNHOLE TESTING EQUIPMENT  

Slip Joints

A slip joint compensates for the movement associated with ocean heave or temperature change without allowing the movement to disturb the placement of downhole tools. A slip joint operates by balancing its volume. As the slip joint stretches and increases its internal volume, a differential piston within the slip joint allows the same volume of fluid into the pipe. The net result is no change in internal volume. Each slip joint has 5 ft of travel but can be combined with other slip joints to provide additional travel. Slip joints are designed to transmit the torque or rotation required to operate tools such as packers or safety joints. When multiple slip joints are run, they are normally connected together rather than located throughout the pipe string. The number of slip joints required depends on ocean heave and the amount of expected contraction and expansion.

Features and Benefits

•  Provides a variable-length joint to allow expansion and contraction of pipe during testing or stimulation

•  Helps space out the workstring when the subsea tree is landed

•  Keeps vertical movement of drilling vessel from disturbing tool placement

•  Provides free travel in workstring to reciprocate tools

Operation

The weight of the workstring (excluding tools, anchor, and traveling blocks) is used to determine the location of the slip joint. The slip joint(s) are placed above the necessary packer setting weight.When multiple slip joints are used, the top joint makes its complete travel, then the next joint down makes its travel, and so on. The weight indicator may show a slight bump as each slip joint reaches the end of its travel.

   

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Subsurface Testing Equipment

III. SUBSURFACE TESTING EQUIPMENT

Ocean Floor Package

The SSTT consists of two full-pening/normally closed, fail-safe safety valves and a latchrelease connection. The valve section contains two tubing closures. Each closure operates independently of one another, and each relies on a single hydraulic source to hold it open. A normally closed . apper valve and a ball valve are closed by a nitrogen chargeassisted spring force.

The nitrogen charge forces the ball to sever wireline or 1.25-in. OD, .125-in. wall thickness coiled tubing. A short time delay between the nitrogen charge and ball/. Apper closure allows severed wireline or coiled tubing to be pulled clear of the . apper before closure. The latch section consists of a latch to the valve section, a flapper-operating piston, and molded seals. The latch section is designed to quickly release the handling string from the SSTT in case of an emergency.

Features and Benefits

• Normally closed, fail-safe valve

• Releases quickly from the handling string in case of emergency

• Functions as a safety device

• Maintains pump-through capabilities at all times

• Nitrogen dome charge chamber provides increased closing force and lessens the time required for closing

• Can unlatch under tension

• Redundant seal design

• Chemical injection at the valve body, further downhole to an injection sub, or to actuate a sub-surface safety valve

• Capable of cutting 2-in. OD, .125 wall-thickness coiled tubing

         
Super Tree II™
P/N   617.10100 617.10200
OD In (cm) 13.00 (33.02)                13.00                    (33.02)
ID in. (cm)   3.00 (7.62)

 2.7 5

(6.99)

End Connections­ 4 1/2 - 4 ACME 5-4 ACME
Latched Length in. (cm) 67.45 (171.32)   71 .9 (182.63)
Unlatched Length in. (cm) 45.9 (116.59) 51.4 (130.56)
Tensile Rating* lb (kg) 400,000 (181,000) 400,000 (181,000)
Working Pressure** psi (kPa)   10,000 (69,000) 15,0 00 (103,500)
Service H2SH H2S
Temperature Range °F (°C) 0 to 300 (-18 to 149) H2 

Lubricator/Retainer Valve

The Lubricator/Retainer Valve is a tubing-retrievable valve. The placement of the valve in the subsea welltesting string determines whether the tool functions as a Lubricator or Retainer Valve. The valve can function as either a normally open or normally closed/fail-safe ball valve. It is operated from the surface by control lines. When used as a Lubricator Valve, it is installed at a predetermined depth beneath the drill floor. The valve and the workstring above it serve as a lubricator for wireline tools. This installation replaces the need for surfacemounted lubricators. In the lubricator position, the valve can also be used to prove the integrity of the lubricator section by pressure testing from above. When used as Retainer Valve, it is installed directly above the Subsea Test Tree (SSTT) near the ocean floor. Its primary function is to capture well. Fluids that would be trapped in the handling string during an unlatch of the SSTT.

Additionally, the valve can be used to prove the integrity of the handling string before the well is brought on line.

Features and Benefits

• Retainer dual mode cabilities: normally open or

normally closed/fail-safe

• Can be used as a Lubricator Valve for wireline tools

• Can be used as a Retainer Valve to capture well . uids from the handling string

• Normally open holds pressure from below and

selectively seals from above

         

Lubricator/Retainer Valve

P/N 617.20100
617.20300
OD In (cm) 10.75 (21.31) 10.75 (21.31)
ID in. (cm) 3.00 (7.62)           2.7 5 (6.99)
End Connections­ 4 1/2 - 4 ACME 5-4 ACME

Length

in. (cm)

71. 44 (181.46)

74. 64(198.59)

Tensile Rating* lb (kg)

 400,000

(181, 000))

  400,000

 (181,000)

Working Pressure** psi (kPa) 10,000 (69,000) 15,0 00 (103,500)
Service H2SH H2S
Temperature Range °F (°C) 0 to 350 (-18 to 177) 0 to 350 (-18 to 177)

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