technical review invision offshore system...slickline, wireline and coiled tubing runs. the system...

Client: BP America Atlantis Team

Project: DC311 & DC 133 Intervention

Title: Technical Review - inVision System

Technical Review – inVision Offshore System

September 2018

DC311 & DC133 Intervention

BP America Atlantis Team

Abstract:

Intelligent Wellhead Systems, developers of the inVision System, deployed a 2nd Generation inVision System

in co-operation with BP America and Oil States Energy Services to the Helix Q5000 servicing BP assets DC311

and DC133. The purpose of the deployment was to fulfill a technical trial of the system and perform an

analysis of its capabilities and future contributions to BP America’s operations in the Gulf of Mexico.




Table of Contents

1.0 Executive Summary ............................................................................................................................. 3

1.1 Findings Summary ........................................................................................................................... 3

2.0 Technical Trial Objectives ................................................................................................................... 3

2.1 Coiled Tubing Risks and Objectives ................................................................................................. 3

2.1.1 False Tag-Out .......................................................................................................................... 4

2.1.2 Coil Connector Separation ...................................................................................................... 4

2.1.3 Personnel in the Red Zone Performing Visual Inspections ..................................................... 4

2.2 Wireline / Slickline Operations ....................................................................................................... 5

2.2.1 Tool Trap Complications and Visual Confirmation .................................................................. 5

2.2.2 Eliminate Bump-Up Procedures and Exposure to Fishing and Well Control Issues ................ 5

2.2.3 Verify False Bump-Up’s and Inadvertent PCE Closure ............................................................ 5

3.0 Planned System Integration ................................................................................................................ 6

3.1 inVision Offshore System: Planned Integration Phase 1 ................................................................ 6

3.2 inVision Offshore System: Planned Integration Phase 2 ................................................................ 6

4.0 KPI Criteria and Findings ..................................................................................................................... 8

5.0 Operational Review and Risk Mitigation........................................................................................... 11

6.0 Future Vision, Capabilities and Marinization .................................................................................... 12

7.0 APPENDIX A – November 1st – November 21st 2017 Technical Field Trial DC-133.Error! Bookmark

not defined.

8.0 APPENDIX B – Report Summaries DC311 ............................................. Error! Bookmark not defined.

9.0 APPENDIX C – Report Summaries DC133 ............................................. Error! Bookmark not defined.

10.0 APPENDIX D – Feedback ................................................................................................................... 14

11.0 APPENDIX E – Technical Trial Proposal ................................................ Error! Bookmark not defined.




1.0 Executive Summary

The inability to accurately and safely determine the location of tool string components within Pressure

Control Equipment (PCE) presents operational challenges for both service providers and E&P’s. The

negative results of incorrectly closing PCE or operating well intervention equipment without empirically

knowing the location of key tool string and BHA components has resulted in significant HSE events and

monetary costs.

Intelligent Wellhead Systems has developed the inVision Offshore System; a technological innovation that

measures and visualizes the presence of coiled tubing, wireline and associated components within

pressurized zones of the PCE stack. Providing users with the critical knowledge of knowing when it is safe

to close PCE and/or stop equipment hence saving time and reducing risks.

In collaboration with BP America and Oil States Energy Services; Intelligent Wellhead Systems performed a

technical trial of the inVision Offshore System during interventions on BP assets DC311 and DC133.

The intent of the technical trial was to demonstrate the application of this technology in coiled tubing,

wireline and slickline interventions. Details of the technical trial and a summary of the overall findings are

shown below.

1.1 Findings Summary

The Gen 2 inVision System performed as per OEM specs over the course of 2 months on multiple

slickline, wireline and coiled tubing runs. The system saved time, eliminated HSE risks, provided

peace of mind to rig operators performing critical tasks and gained user confidence over time.

2.0 Technical Trial Objectives

The technical trial objectives were developed for coiled tubing, wireline and slickline interventions. The

premise of the trial was to determine for each type of intervention; how the addition of Intelligent

Wellhead Systems – inVision System technology would improve overall intervention performance and

reduce or eliminate the operations exposure to HSE risks.

2.1 Coiled Tubing Risks and Objectives

Current SOP’s in non-slick BHA retrieval operations require the coiled tubing operator to slow the

injector speed at specific depths, typically 500’ and 200’ from surface, staging down retrieval rate

from 60’/min to 5’/min.

The coiled tubing operator uses weight indicators to identify an over-pull, which typically occurs

when the BHA contacts the coiled tubing stripping head. The operator immediately stops the

injector when an over-pull is identified at which point it is assumed the BHA is clear of the FSV and




the well is shut in using hydraulic power. This procedure costs valuable time and presents multiple

HSE and well control risks. The primary examples of these risks and corresponding trial objectives

are detailed below:

2.1.1 False Tag-Out

There are instances where false tag outs can happen. For example; a hydrate build up in

the BOP stack, or a foreign object lodged in a BOP cavity creating an obstruction. In both

cases the operator can mistakenly think a tag out has occurred and shut the PCE on tubing

or tools causing expensive damages and potential well control incidents.

2.1.1.1 False Tag-Out Trial Objective

Use the inVision System to identify when tubing and BHA’s are clear of critical PCE

and it is safe to close the swab valve or flow head master valve.

2.1.2 Coil Connector Separation

The bump up procedure can impose undue force on the coil connector causing it to

separate from the BHA resulting in fishing operations, well control incidents and/or human

injury.

2.1.2.1 Bump-Up Procedure Trial Objective

Develop an improved procedure utilizing the inVision System to identify when it is

safe to close PCE – there by eliminating the need for bumping up - reducing the

operations exposure to coil connector failures and the associated remedial costs.

Further development and cooperation with service companies can enable an

engineered fail-safe stop of the injector head if an imminent collision is detected.

2.1.3 Personnel in the Red Zone Performing Visual Inspections

The need for sending personnel into the red zone arises when a visual

inspection/confirmation of the coil connector is required. This operation places personnel

at risk during one of the most critical times of coiled tubing retrieval.

2.1.3.1 Reduce Personnel in the Red Zone

The inVision System allows easy identification of key coiled tubing BHA

components from the safety and convenience of a remote location such as the

coiled tubing operators cab. The system allows this information to be viewed and

monitored by anyone on deck with access to an inVision HMI.




2.2 Wireline / Slickline Operations

Current SOP’s require the Wireline/Slickline operator to slow down retrieval rate at 300 ft. from

surface and rely on tool traps and tag out procedures to verify the BHA is clear of critical PCE. In

addition, a man is required to enter the ‘red zone’ and visually monitor tool trap function and/or

pull down on the moving wireline to assist with a ‘soft tag-out’. These procedures cost valuable

time and present multiple HSE and well control risks. The primary examples of these risks and

corresponding trial objectives are detailed below:

2.2.1 Tool Trap Complications and Visual Confirmation

Sending personnel into the red zone to monitor tool trap function places personnel at risk

of potential harm should the wireline break or other unplanned incidents occur.

Additionally, tool traps utilize mechanical components within the pressure contained area

of PCE, exposing the operation to mechanical failure of the tool trap and associated

components.

2.2.1.1 Elimination of Reliance on Tool Trap and Visual Confirmation

Utilize the ability of the inVision System to identify without contacting the tool

string when the tools enter the stack and when the end of the tool string clears the

wellbore isolation valves. This serves as a method of replacing the need to send

personnel into a hazardous area to observe tool trap functions and could

potentially eliminate the use of tool traps altogether. inVision can be tied into a

wireline operating system and trigger the brakes if an imminent collision with the

stuffing box is detected.

2.2.2 Eliminate Bump-Up Procedures and Exposure to Fishing and Well Control Issues

The tag out procedure can impose undue force on the cable head causing it to fail dropping

tools downhole or at surface on the deck

2.2.2.1 Eliminate the Requirement for Bump-Up Procedures

Further reduce the operations risk exposure by eliminating the requirement for

any bump-up procedure by utilizing the inVision Systems visual and audible alert

system to confirm PCE is clear of tools and that it is safe to shut in the well.

2.2.3 Verify False Bump-Up’s and Inadvertent PCE Closure

False bump-ups are known to occur and can cause the operator to function PCE when

wireline or tool string components are across PCE. False bump-ups usually occur at critical

times and can be caused by many factors. i.e. Line Friction, Hydrates, foreign objects lodged

in PCE, human error.




2.2.3.1 Tool String Location and Verification Capabilities

The inVision System identifies the existence and location of wireline and tools

within the pressurized zones of the PCE stack and displays this for the wireline

operator to see and confirm when it is safe to close PCE.

3.0 Planned System Integration

Integration of the inVision Offshore System was rolled out in two phases. The first phase was used to

establish a performance baseline and to allow for operators to develop confidence in the system. The

second phase was used to determine improvement in performance with the system being utilized by the

equipment operators.

3.1 inVision Offshore System: Planned Integration Phase 1

1. Rig in 7 1/16” x 10M inVision Spool directly on-top FSV

2. Run Crossover to PCE on-top of inVision spool

3. Rig in support equipment on deck

4. Rig in screens to CT/WL cabin and Helix drillers cabin

5. First WL and CT runs completed without relying on inVision data

6. IWS technician to be present capturing baseline time data defined as; [moment WL/CT

pulling speeds are reduced to the moment the FSV is shut]

7. During this exercise the CT/WL operator will be able to monitor performance of inVision

system and gain confidence.

8. Data being logged will be produced to BP reps.

3.2 inVision Offshore System: Planned Integration Phase 2

1. With baseline data captured and confidence in system acquired stage 2 of the field trial will

commence on the second well.

2. IWS technician monitoring system performance and present with WL/CT operator a time

data point will be commenced when WL/CT typically slows down.

3. The WL/CT operator will pull at a comfortable speed knowing they will get alerted the

moment the BHA enters the inVision spool.

4. The IWS technician will note the depth counter the moment the BHA enters stack.

5. The WL/CT operator will pull the BHA through the stack at the speed of their discretion and

stop when the inVision spool alerts the BHA is clear of the FSV.

6. The depth counter will be noted again and correlated with the known length of the BHA

7. The FSV will be closed.

8. The time data point will be noted




The system was installed below the service providers BOP’s. Figure 1. Outlines where the inVision System

was installed during coiled tubing operations. The installation of the system in this location allows for

operators to clearly identify when the BHA is clear of the FMV and when BHA components are positioned

with in the coiled tubing BOP’s.

Figure 1. inVision System installed below Coiled Tubing PCE

Coiled Tubing Injector

Coiled Tubing BOP

inVision System

FSV




4.0 KPI Criteria and Findings

The following KPI criteria was developed for the technical trial proposal. Appendix B and C contain the

original log files and shift notes from operations. The summarized KPI findings are detailed below:

1. Did the system rig in with no additional critical path time added?

First Rig-up on DC311 occurred offline during IRS checks. A 7-1/16” 10M x Bowen Cross-

Over was installed on top of the inVision System and then the assembly was installed above

the flow-head. Second rig up as per normal procedure adding no downtime on DC311 Rig-

up on DC133 was achieved in a similar fashion during installation of the wireline PCE.

The addition of the inVision System did not add critical path time to the operation. At no

point were operations waiting on any facet of the inVision System installation.

2. Did the system rig in with no operational hazards added?

The inVision System did not add any operational hazards. The Gen2 inVision System was

designed to fit within the bails of the Q5000 and allow for safe mechanical clearance of the

bails. Feedback from service personnel highlight the systems compact design. For service

personnel feedback see Appendix D.

3. Did the system perform as per the OEM technical specifications?

The inVision System did not fail to measure and record coiled tubing, wireline or tool string

components as outlined in the system specification. For the interventions completed on

DC311 and DC133, the system successfully measured and recorded the following

equipment:

• 28 HES slickline BHAs

• 28 Slickline runs totaling 622 388’ of 0.125” extra ply steel slickline.

• 2 Schlumberger/Baker BHA assemblies

• 2 Wireline runs totaling 67 410’ of 0.320” wireline

• 2 HES Coil BHA

• 2 Coiled tubing runs totaling 72 550’ of 1.75” tubing.

An example of the inVision System user interface can be seen in Figure 2. This image

displays the user interface as seen when detecting the wireline rope socket and weight bar.

Note the profile display to the right of the image making for easy tool or component

identification. The center display depicts the lateral tool location within the wellbore. In

this image the tools are running in hole slightly off center. Alerts and other important

information is displayed on this interface that is easily accessed by the operators.




The inVision System features a magnetic retraction system for use during magnetically sensitive operations.

This system was utilized at the request of Baker personnel while running portions of the BHA’s containing

cutter tools. The system functioned as designed resulting in no additional critical path time or risk to

sensitive BHA components.

Figure 2. inVision System Detecting Wireline, Rope Socket and Weight Bar

4. Did the system create a savings in critical path rig time?

During wireline operations the Supervisor instructed the Driller to close the lubricator valve

when the inVision System detected the cable head reducing the retrieval time for wireline

tools.




The inVision System assisted during coiled tubing operations and was used to locate the

coiled tubing within the CT pipe rams during pressure tests saving critical path time before

running in hole.

4.1 Outstanding Critical Path Time Savings:

On retrieval of coiled tubing the system assisted the HES CT Supervisor in locating the

BHA and confirming when it was safe to close PCE saving 14 minutes on retrieval of the

first coiled tubing run.

On DC133, while Slickline was setting the Plug Body Assembly, Primary Depth Counter

failed at 5121’ while pulling out of the hole. The inVision System made it safer and

more efficient to pull out of hole with them relying only on their Secondary Depth

Counter. Once out the hole with the Plug Body BHA, permission was granted to run a

2.8” Gauge Ring Assembly to above the Profile Nipple @ 18 333’ and come out the hole

utilizing Secondary Depth Counter and the inVision System.

See point #6 below for addition critical path time savings event.

5. Did the system eliminate any safety risks relating to people?

For all operations the system provided the additional information of confirming the

location of critical BHA and tool string components while pulling out of the hole.

For wireline and slickline operations the cable head was used to identify the beginning of

the tool string, indicating to the operator that the tools are at surface. The operators were

able to correlate the position of the inVision System within the PCE stack and use this to

visualize the location of the tool string components as they were pulled out of the hole. By

using this system, the wireline / slickline operators did not send personnel into the red zone

to assist in performing a soft bump-up. See Appendix D for operator feedback on increased

safety.

6. Did the system mitigate any well control risks relating to equipment/environment?

While pressure testing coiled tubing equipment the inVision System was used to safely and

accurately position coiled tubing across the pipe rams within PCE for pressure testing

purposes, eliminating the well control issues that arose from incorrect coiled tubing

placement and BOP closures.




7. Did the system reduce the WL/CT operators stress level?

The inVision System reduced operator stress levels by providing them with a clear and

intuitive user interface that displays critical information as to the location of tool string

components within the pressurized zones of the PCE stack. This information has not

previously been available to operators and the ability to see inside the PCE stack was

viewed as a great benefit to them. Feedback to this effect has been captured from wireline,

slickline and coiled tubing operators and is available in Appendix D.

8. Did the IWS technician perform duties in a professional manner?

The IWS Technician performed all duties in a professional manner. Feedback from

personnel on deck supporting this notion can be found in Appendix D.

9. Did the Oil States technicians understand how the system works and how to operate

it?

The system was picked up by 3rd-party personnel quickly. It is designed to rig-up and

operate intuitively and utilizes thoroughly tested software to ensure operators can easily

learn to use the system. Feedback from users of the equipment supporting this argument

is attached in Appendix D.

10. Did the BP Wellsite leaders obtain data reports produced by the inVision System?

Data reports produced by the inVision System are available in Appendix B and C. The

reports contain information including in hole / out of hole times, tool string dimensions and

other critical information. The system generates log files that enable complete user

interface playback and access to other critical information that can be used for incident

investigations or NPT disputes. This information can be made available upon request by

approved personnel.

4.0 Operational Review and Risk Mitigation

The inVision System has the unique ability to measure, visualize and record tubing and tool string diameters

and profiles; displaying this information on an intuitive user interface within the operator’s cab. Providing,

in real time, a visualization of the operator’s tool string as it moves through the PCE stack.

This valuable information enables the development of new operational procedures which are not

achievable and could not be considered without the information that the inVision System provides.




In doing so the inVision System enables improved operational performance and eliminates key HSE risks

completely. This is achievable by allowing for the development of new procedures and SOP’s that utilize

the advanced information made available by the inVision System. A summary of key operational changes

is detailed below:

• Eliminate the need to bump up by utilizing the inVision System to confirm when the end of

the BHA or tool string is clear of PCE and it is safe to close in the well.

• Utilize the inVision System during fishing operations to confirm fish retrieval and to confirm

that the fish, which may be of un-confirmed length, is clear of PCE and that is safe to close

in the well.

• Identify the end of parted coiled tubing using the inVision System and confidently close

PCE. Eliminating the risk of pulling parted coiled tubing through the stuffing box, or closing

PCE on tubing or wireline

• When pulling out of the hole, reduce the depth at which retrieval rates are slowed, utilizing

the inVision System to alert operators of the detection of the coiled tubing BHA or wireline

tools when they enter the inVision Spool be it subsea or at surface.

• Decrease retrieval and coiled tubing unloading times by using the inVision System to

streamline the procedure safely and efficiently.

In co-operation with service providers, E&P’s and with due diligence in regards to management of change

policies the inVision System can be used to develop new procedures on an ongoing basis. The system

provides unparalleled insight into the PCE stack changing the scope from which critical decisions can be

made.

5.0 Future Vision, Capabilities and Marinization

Intelligent Wellhead Systems is committed to continual development of the inVision Offshore System to

fully realize the technologies potential and further assist offshore operations in safely and efficiently

achieving their goals.

Intelligent Wellhead Systems through a joint venture with Trendsetter Engineering, is developing a subsea

inVision System– currently undergoing preliminary testing.

This project allows the inVision System to be placed at key locations within the riser assembly enabling the

same advanced technology to be used subsea. Figure 2. Illustrates the placement of three systems in a

deep water intervention. The upper system functions as described in this technical trial report; the two

remaining systems are subsea, located above the lubricator valve and subsea tree.

The advantages presented by the inVision System technology in this configuration are numerous and

represent a significant technological and procedural advancement for offshore intervention operations.




Figure 3. Intelligent Wellhead Systems - Trendsetter Subsea Development

6.0 APPENDIX D – Feedback

technical review invision offshore system...slickline, wireline and coiled tubing runs. the system...

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