CLYDE & CO
INCE & CO
ADC was tasked by a Client to carry out rig selection surveys on three “warm stacked” Dynamically Positioned (DP), DP3 Class Drillships that had been shortlisted by the Client. ADC was to produce a survey report for each rig and, following completion of the surveys, deliver a summary report comparing the audit findings from each rig. This purpose of the comparison report was to enable the Operator to select the rig best aligned with their Operational, Safety and Environmental requirements.
The 3 shortlisted Drillships were warm stacked in various locations globally which presented a logistical problem due to the short timescale available to conduct the surveys. On review of the rig specifications, they all appeared to be very similar in capability; 6th or 7th Generation Drillships, Ultra Deep Water, DP3, dual activity derrick, automated drillfloor.Therefore, in order to provide a clear indication of which rig was best suited, ADC required an in depth understanding of the client’s specific requirements.
ADC considered that greater clarity of client requirements was needed. Utilising experience from similar previous exercises, ADC produced a suggested list of criteria and requested the client to specify a capability or requirement next to the criteria and specify whether this was essential or desirable.
Having then established a clear understanding of the client’s specific operational, safety and environmental requirements, robust inspection checklists were prepared to facilitate a consistent inspection evaluation. This in turn provided a platform for the practical comparison of the rigs following the rig selection survey visits.
Due to the short time frame in which the rig selection surveys were to be completed, ADC provided 2 teams of 3 Specialists to accompany Client representatives during the respective rig visits. Their remit was to assess the Rig Equipment, Integrated Control Systems and Health, Safety and Environmental aspects of the rig selection.
In order to consistently report on the specific requirements defined during the planning stage, both teams employed ADC’s reporting tool TRAMS. The standardised survey checklists had been prepared prior to mobilisation to each rig and significantly contributed to the consistent nature of the survey reports. The developing survey final reports were also reviewed by ADC Office Support in real time utilising TRAMSweb to ensure consistency and further enabled the prompt delivery of the summary reports.
The Client had shortlisted rigs which it considered would fulfill the requirements. However, whilst the specification looked virtually identical on paper, it was quickly recognised during the survey process that the rigs were significantly different in capability. When compared to the requirements, all of the rigs visited had strong points and weak points and a sample of capability findings is provided below.
- All rigs had automated drill floors. However, some had a basic NOV Cyberbase system fitted whilst others were more advanced with Multi Machine Controller systems for more efficient operations.
- All were listed as having dual activity derricks. Dual activity is not clearly defined and it was found that a spectrum of capabilities existed, some having a greater capability of dual activity operations available than others.
- Some rigs had active heave drawworks, some had active and passive heave compensation systems and some had combinations of both.
- All rigs were DP3 Class. However, some were better suited to deep water operations and operating in areas where Differential Global Positioning Systems (DGPS) can be problematic. Some rigs utilised Inertial DGPS systems and Hydro Acoustic Inertial Navigation (HAIN) Systems. The inclusion of inertial sensors improves system stability in the event of loss of DGPS signals and in the case of HAIN improves the deep water Hydro acoustic update rate to the DP system.
All of the rigs were described as warm stacked but had different policies and procedures relating to the stacking process and planned maintenance during stacking. These were reviewed and varied between virtual cold stacking where there are greater risks associated with reactivation and lower risk hot stacked procedures where virtually all equipment was routinely operated. Following the rig selection visits of the three rigs one rig in particular was found to largely comply with the requirements set out at the planning stage. In comparison the others were found to not meet the requirements in a number of areas.
Without inspecting the rig, driven purely on a cost basis and using a desktop analysis it would have been very easy for the client to be left with a rig which on paper, meets the requirements but in practice falls well short of the capabilities required.
Had the maintenance system during stacking not been reviewed, a potentially, “colder” stacked rig may have been selected. This has potential consequences regarding the condition of bearings which can fail a short time after reactivation and Variable Frequency Drives which can be problematic if not reactivated correctly.
Without doubt all of the non-conformances that were found could have been addressed by the drilling contractors. However, by identifying these early in the rig intake process the consideration of schedule and financial impacts from necessary remedial works could be measured and considered at the rig selection process.
Not all DP3, dual activity derrick Drillships are created equal.
They may all be able to do the job, but there will be different levels of capability, efficiency, competence and safety.
For ADC it was important to: - Clearly define the full operational requirements of the Client. - Plan how these requirements will be consistently reported upon. - Create a standardized checklist that can be applied over multiple rig selection surveys.
All of the rigs were all described as warm stacked but had very different policies and procedures relating to the stacking process and planned maintenance during stacking. The risks associated with reactivation varied widely between rigs and should be assessed based on the maintenance plan conducted.
Conduct of a thorough rig selection survey onboard provides a clear indication not just of the machinery but the management, the crew and the overall capability.
ADC’s rig selection methodology is sound and provided the client with factual information regarding rig capability, equipment condition, and maintenance and reactivation schedules.
ADC presented a balanced comparative study and identified where each rig was strong or weak with regard to their operational requirements and this assisted the client to make a factually based balanced decision regarding the best equipment, management and crew for the forthcoming drilling campaign.
ADC was tasked to assess several rigs to meet specific operational requirements as part of a rig selection survey.
During the rig selection process, the Drawworks were operated to provide evidence that a software fault that caused blinking indications on the Weight on Bit display had been rectified and screen indications confirmed this to be functional.
Upon further inspection of the NOV Cyberbase system by ADC, it was discovered that one drawworks motors was unavailable and that communication to one of the Central Processor Units (CPUs) had failed. The system was designed to operate with 2 CPU’s, one of which was meant to operate in a hot standby mode. It was subsequently found that one of the CPUs was unserviceable and that the communication problem with the CPU also created various system fault indications within the Drawworks Control Cabinet.
The drawworks was not operating with full capacity available due to the unavailable motor and there was no redundancy in the active heave drawworks control system.
With no redundancy, a single failure within the drawworks heave system would have rendered the system unavailable, potentially resulting in serious damage to drilling equipment in the high sea state conditions anticipated in the operating area.
LESSONS LEARNED ADC did not accept that the drawworks was fully functional based on the closure of a previous non-conformance. The ADC control system inspection regime takes into account software, network communication, equipment availability and redundancy capability by a systematic approach to inspection which provides consistent results.
Aberdeen Drilling Consultants Ltd (ADC) were awarded a contract by an Oil and Gas Operator to perform an inspection of a subsea BOP during an End of Well (EOW) maintenance period and witness the work and workscope carried out on the BOP and Well Control Equipment (WCE).
ADC was awarded a contract by an Oil and Gas Operator to perform an on-board inspection of a 5th Generation BOP and MUX Control System and to witness the ongoing End of Well maintenance work.
ADC mobilised a Subsea BOP Specialist to the rig to monitor and report to the client on the progress and workscope being undertaken by a drilling contractor during a planned EOW workscope.
This included visual inspection of the BOP and WCE witnessing and reporting on pre-deployment testing phase. Testing was carried out in accordance with the Well operator (Duty Holder) procedures and API Standard 53 requirements.
As a critical element of both the Well Operators Procedures and API S 53 the design, condition and functional operation of the BOP ROV Intervention System and 3rd Party ROV Pumping Skid equipment were inspected, function tested and their compatibility and suitability observed.
SUMMARY OF OBSERVATIONS
The BOP inspected was an NOV Shaffer NXT 18-3/4", 15K stack with 2 annulars and six pipe rams.
The stack was equipped with multiple ROV intervention panels, an Acoustic Pod and an Emergency Hydraulic Backup System (EHBS).
Two ROV intervention panels were installed on the LMRP and twenty ROV intervention panels on the lower stack. The functions provided for were in excess of the minimum requirements of API S53
API S 53, Section 184.108.40.206.1 states: The BOP stack shall be equipped with ROV intervention equipment that at a minimum allows the operation of the critical functions (each shear ram, one pipe ram, ram locks, and unlatching of the LMRP connector).
In addition to the ROV stab receptacles three flying leads were equipped with stabs.
During a review of historic topside BOP ROV intervention tests, using an ROV test pump to simulate the actual pressure and flow which would be expected from an ROV intervention, the following function timings were noted:
All timings reviewed did not comply with API S53, Section 220.127.116.11.16:
'All critical functions shall meet the closing time requirements in 18.104.22.168.4. - (a) close each ram BOP in 45 seconds or less; c) unlatch the riser (LMRP) connector in 45 seconds or less'
In order to improve these timings and to comply with API an uprated system for the ROV BOP intervention skid was supplied by a 3rd party. The upgrade was a High-Low Pump BOP intervention skid. The skid was a modification and was designed to be fastened below the ROV.
The intervention skid comprised 4 hydraulic reservoirs which had a total capacity of 130 gallons. The pump set was capable of pumping fluid in two phases:
65 GPM up to 1200 PSI. 20 GPM up to 5000 PSI.
The fluid was delivered via a flying lead and a stab.
On inspection it was found that all of the BOP ROV intervention panel receptacles and flying lead stabs were of the same design; dual-ported and all connected with 1/2” bore hose.
The flying lead stab and the receptacles were duel port design with only the pin end port connected. The receptacle port was 3/8” NPT threaded, fitted with a 3/8” NPT to 1/2” JIC fitting.
A 1/2” hose then connected the receptacle to the shuttle valve of the function.
The flying lead was connected to the hydraulic supply by a single 1/2” hose connected pin end port. The pin end port on the stab was also by a 3/8” NPT to 1/2” JIC fitting.
The duel port design of the critical function receptacles did not comply with API S53:
API S 53 Section 22.214.171.124.3 states: All critical functions shall be fitted with single-port docking receptacles designed in accordance with API 17H.
In accordance with API S53 and API 17H, receptacle should be 1” High Flow Type C. The stabs and receptacles fitted to the BOP were found to be Type A. The dual-port design, the fittings and the 1/2” hose would all restrict the flow of fluid to the critical function operators.
The commissioning of the High-Low Intervention skid was witnessed by the ADC inspector. Pressure and flow rates were confirmed with the first stage pump delivering 65 GPM at 1,200psi and the second stage pump delivering 20 GPM at 5,000psi.
A pump rate of 65 gallons would give a theoretical closing time of the largest operators of 43.5 seconds.
An inspection of the High-Low intervention skid revealed that the skid was equipped with a 1” bore hose. The hose connected the pumping system to the stab. The stab was a 1” High Flow Type C.
It was demonstrated that a Type C stab (as fitted to the Intervention skid) would fit in a Type A receptacle (as fitted to the BOP). The ports on the stab would also line up with the panel side port of the receptacle.
This was also confirmed by the dimensions provided by API 17H, Figure 17- Type A receptacle and Figure 20 - Type C stab.
The ROV Intervention Type C stab may have fitted the Type A receptacle, however the porting of the receptacle and the 1/2” hosing fitted to the BOP would have restricted the flow of the fluid from the stab therefore not allowing the intervention skid to operate the critical BOP functions as designed.
Therefore the timings for the operation of Critical functions would not have complied with API S 53 and could have delayed the shut-in of a well if operated in a real time well control situation.
ADC was tasked to provide operational support of jacking systems during rig moving operations.
Throughout the course of the drilling campaign, the rig crew had been changed out and were unfamiliar with the jacking system prior to the arrival of ADC. They were not trained in the specific jacking system equipment, functionality, modes of operation or procedures and processes. The jacking system had been started up but due to the large number of faults and alarm, the crew elected to switch it off and leave it off.
When ADC arrived, the jacking console was switched on there were multiple alarms that would not clear. The rig crew were unfamiliar with the meaning of the alarms or of their implications. ADC worked through the Alarm list with the crew systematically addressing and correcting the faults and clearing the associated alarms to achieve a fully operational jacking system.
Maintenance As a result of the crew’s unfamiliarity with the jacking system, there had been a reluctance to conduct checks or maintenance work on the system. The maintenance procedures for the yearly Jacking System inspection were reviewed by ADC and were considered to be unfit for purpose because many of the systems and components, essential to correct function of the jacking system, were not covered by the maintenance procedures provided. Consequently, it was considered that very few of the faults that were identified during ADCs inspection could have been detected by the crew or have been prevented by using the maintenance work orders in place at the time.
System Damage Significant damage had been caused to the Rack Phase Differential (RPD) measurement system which is used to measure the difference between individual chord heights. Wiring had been ripped out of the rear of one encoder communication modules. It was found that the RPD measuring wheel mechanism had been sticking due to lack of lubrication. It was further established that the connecting cables were too short to permit RPD wheel retraction from the Rack to permit rotation and lubrication application to free it off. It was considered that the cable and module damage may have occurred whilst the crew were trying to free off the wheels and lubricate them. ADC identified the fault, confirmed the availability of a spare communication module and confirmed correct system communication following the repair.
The lack of crew familiarity with the equipment and out of date maintenance procedures had resulted in damage to RPD monitoring equipment. The control system prevented operation of the Jacking System due to the lack of monitoring and the possibility of leg structural damage.
The crew were unfamiliar with the implications of the alarms and had the crew used the RPD override facility, it could have resulted in severer damage to the Jack up legs due to the lack of RPD information.
Due to the large number of faults, equipment damage and lack of operator familiarity, it was considered that without ADC participation that the jacking operation could not have occurred.
Modern control systems are designed to protect the equipment, vessel and prevent operator error. In order to achieve this it is essential that crews are adequately trained on the systems that they are operating. This includes understanding the equipment, the principles of operation and the meanings and implications of alarms. Adequate documentation of the systems must be available to the crew to explain the meaning of alarms and fault indications. Maintenance procedures must adequately reflect the equipment and systems onboard.
Aberdeen Drilling Consultants Ltd (ADC) were awarded a contract by an Oil and Gas Operator for the provision of drilling rig acceptance services covering MODU Systems, Well Control Equipment, Dynamic Positioning Systems and Power Management, Safety Management, Environmental Compliance and Dropped Objects. These services were to be conducted onboard a 6th Generation dynamically positioned drillship prior to the commencement of drilling operations and spanned two separate inspection periods; the first being a shallow water phase conducted at anchorage and the second a deep water phase on the drilling location. The two stage approach was adopted to enable the witness of realistic operational scenarios.
ADC were awarded a contract by an Oil and Gas Operator for the provision of drilling rig acceptance services; the objective of which was to assess the rig fit for purpose and to ensure it could be safely operated in accordance with applicable Client, regulatory and statutory requirements for the region. This project afforded ADC the opportunity to showcase their all4one approach to rig inspection and acceptance.
ADC engaged all stakeholders early after contract award to discuss and agree the programme of acceptance inspection of the drill ship. This process considered the Operators drilling programme as well as being considerate to Client, regulatory and statutory requirements for the area of operations. The outcome from this process was a bespoke acceptance inspection document, derived from the functional design specifications and operability capabilities of the rig that was signed off and agreed by all.
This document was then distributed in a manner that proper planning, materials and resources could be made available when the acceptance inspection was to be conducted. The acceptance inspection was agreed to be conducted in two stages; one in shallow water and the other in deep water. In particular the deep water phase was to enable proper conductance of drilling equipment, power management and dynamic positioning system testing which is typically constrained in shallower inland water ways.
ADC provided suitably qualified and experienced Specialists to be in attendance to conduct the inspections of equipment and subsequent witness of operational testing.
The process was fully supported by the Client and drilling contractor; in particular the rig crew were found to be very competent and could not do more to assist the ADC team during the very comprehensive testing period. The support provided can be best illustrated by the willingness and timely response by the drilling contractor in closing non-conformances as they were recorded; a total of 95 non-conformances were raised during the drilling rig acceptance period with an associated distribution of 9 Critical, 27 Major and 59 Minor. At the time of the final close out conference call, there were a total of 0 Critical, 9 Major and 16 Minor non-conformances open.
During the conductance of the drilling rig acceptance inspection 9 critical and 27 major non-conformances (findings) were recorded. These included the incorrect operation of the slack wire function to the drill floor man rider, failure of the function to operate water tight doors from the bridge, the ROV system was inoperable due to the tripping of the power supply to the tether management system and the drillers choke control panel was found to be faulty. In each instance, each was satisfactorily addressed and closed by the ADC Specialists prior to departure.
It each of the non-conformances (findings) mentioned above they referred to essential equipment and systems that were out with their respective functional design and were being inappropriately used to a point that may have led to loss of life, a serious injury or environmental damage.
The significant lessons learnt was the importance of the development of a proper plan considerate to what was achievable in shallow and deep water, agreeing within all stake holders before commencement what was to be achieved, the resources required and the anticipated timings, maintenance of strong verbal and written communication between the focal points of the Client, Drilling Contractor and ADC during conductance and completing satisfactorily what was originally set out to achieve.
“Just a quick note to say thanks to you and your team for the excellent work carried out on the rig, your teams efforts has played a part in a successful startup with the rigs first month of operation being over 99.6% uptime. This is the reason ADC is the company of choice for rig audit services”.
ADC was tasked to witness a System Integration Test of a Drilling package.
The ADC specialist considered the results of a system integration test conducted by the original equipment manufacturer (OEM) to be lacking due to the omission of certain operational scenarios.
An ADC test plan was produced to provide assurance that the drilling package operated correctly under normal conditions. The content of the test was agreed between ADC and the Drilling Contractor Operations Department and sequence of events was agreed with OEM. It was considered by ADC that there was an Operational requirement to conduct offline stand building during drilling operations. Therefore, the auto driller system was used to move the top drive up and down during stand building operations.
During the test, this simultaneous operation caused a Zone Management System (ZMS) problem. When drillfloor equipment was moved, the drawworks stopped lowering. ADC recognised that the fault lay in the ZMS functionality and suggested that the computers drill floor height value may be in error. OEM engineers reviewed these settings and found that whilst the ZMS drill floor setting should have risen to 6m during Auto Driller operation, that the software setting was actually 28m and that this error had prevented simultaneous Stand Building and Drilling operations.
Once the issue had been resolved, the OEM demonstrated the correct functionality of the ZMS. This fault was found to be a base line software issue causing a fleet wide problem affecting another 4 rigs and the OEM personnel thanked ADC for their assistance in this matter.
Had ADC not insisted on the conduct of this test, the operational efficiency of a fleet of 5 rigs would have been impaired; simultaneous drilling and stand building operations would not have been possible and a dormant fault in a safety critical system would have remained unidentified.
Operational scenarios must be used during acceptance testing as manufacturer commissioning tests do not always fully consider the interaction between various machines under all envisaged operational circumstances. Consequently, there can be dormant failures that only become evident under a specific set of circumstances.
Incidents and accidents related to tubular handling operations are of significant concern throughout the drilling industry and remain a major cause of dynamic dropped objects.
ADC has been tasked to provide a Tubular Handling Assessments for various rigs in order to ensure that equipment was fit for purpose and identify any single-point human barriers present within the drilling system that could result in dropped tubulars, dynamic dropped objects or equipment damage.
During the periods that the ADC teams were on-board, the rigs have conducted various drilling operations and ADC has witnessed all aspects of onboard tubular handling.
ADC conducted a review of all procedures identified within the Tubular Handling process and a physical inspection of all of the equipment utilised within the process. Operations were witnessed to determine if the equipment was being operated as per the Functional Design Specifications, Operating Instructions and work instructions.
FINDING 1 – FINGERBOARD LATCH FAILURE The Fingerboard consisted of a set of steel fingers dividing the rows of tubular stands. Each finger (row) was equipped with a number of mechanical locking latches which were closed by a mechanical spring and opened by air pressure through pneumatically operated cylinders. The pneumatic latches were described to be of a failsafe design such that if air pressure loss occurred, each of the individual latches would go into locked down position.
Air Pressure must be applied to the pneumatic cylinders to open the latches as required. A valve cabinet located near the fingerboard contained the control valves that directed compressed air from the control valve to the latch cylinders via pneumatic piping hoses.
The control valves within the valve cabinet also sent signals to control system that provided feedback information to the driller that the solenoid was activated and on the drillers screen the finger appeared as a latch open indication.
The fact that the pneumatic solenoid was activated and indicated did not confirm that the finger was actually open. IADC Alert 15-10 Fatality on Drill Floor described an accident where a tubular was caught in a fingerboard latch and the pipe racking system (PRS) was retracted. As the PRS retracted, the tubular was bent and stored energy was released as the tubular was pulled from the lower racking arm gripper. The lower end of the tubular was catapulted back across the drill floor killing one of the rig crew.
This issue is well understood and most rigs use a system of visual back up or CCTV system to confirm that the latches are open prior to moving tubulars in or out of the fingerboard. However, ADC have identified on more than one occasion that from the roughneck’s position outside of the Red zone, it was not possible to see the position of the latches within certain areas of the fingerboards and that lip service was being paid to these checks.
Crew need to fully understand their responsibility to confirm that latches are open prior to moving tubulars and to fully understand the potential implications if latches remain closed.
FINDING 2 – DOLLY RETRACT SWITCH
The Drillers chair Dolly Retract (Left switch) and Elevator links tilt (Right switch) were virtually identical tactile buttons placed next to each other on the right joystick. Both were controlled by a thumb roll forward or back. It was considered to be very easy to inadvertently press the left switch whilst intending to press the right. Regardless of whether the Dolly was selected in Auto or Manual Mode, the Stick top switch was always active.
In Auto mode the Dolly fully retracted upon activation of the switch. In Manual Mode the Dolly retracted only as long as the button was activated.
The lack of an appropriate interlock to prevent inadvertent dolly retraction with tubular connected to the Top drive or elevators was considered to be a major design flaw in the system because inadvertent dolly retraction could result in a bent drill pipe, damage to the rotary table and damage to the top drive.
A suitable modification was required to prevent accidental dolly retraction. Meanwhile, in order to reduce the consequences of an inadvertent selection of this switch, ADC suggested that the dolly should only be operated in manual mode. Thus, if the button was inadvertently activated, the operator would be more likely to identify the movement and cease the operation before the dolly had moved any significant distance.
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