dualgradient system evaluation highlights key highrisk issuesdrilling contractor

7/29/2019 Dualgradient System Evaluation Highlights Key Highrisk IssuesDrilling Contractor

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Figure 1: Unlike convent ional drilling, dual-gradient drilling uses two hydrost atic

gradients. The seawater gradient f rom seasurface to seaf loor is used to manage the

borehole, and the mud gradient f rom the sea

f loor is used to prevent the borehole f romcollapsing and removing cuttings f rom theborehole.

http://www.dri ll ingcontractor.org/dual-gradient-system-evaluation-highl ights-key-high-riskissues-17111 January 29, 2013

Dual-gradient system evaluation highlights key high-riskissues | Drilling Contractor

Study focuses on subsea integration, fluids discharge, maintenance, pump impact on LWD

By Bibek Das, Marco Figoni, Jorge Ballesio and James Bond, American Bureau of Shipping

The of fshore industry frequently develops novel applications and processes that have no t rackrecord in the environment being proposed. These concepts may differ signif icantly from existingdesigns such that the guidance encompassed in current prescriptive rules may not be directlyapplicable. In such cases, risk-informed approaches are adopt ed to aid decision-making.

Dual-gradient drilling (DGD), a variant of managedpressure drilling (MPD), is an example of such atechnology. This article provides an overview of thestudied DGD system and equipment, as well as a

hazard identification and risk assessmentmethodology developed in accordance with the ABSGuidance Notes on Review and Approval of NovelConcepts. Brainstorming sessions with engineersfrom drilling, cont rols, subsea, maintenance andclass have resulted in recommendations that havebeen valuable in reducing and managing risks to aslow as reasonably practicable (ALARP) levels.

A functional failure modes eff ect and crit icalityanalysis (FMECA) was conducted on the DGD

system. The assessment shows t he significance ofdealing with failure issues that can lead to potentialdischarge of wellbore f luids to the sea, as well asthe importance of maintenance, inspect ion andpersonnel t raining. Several topics are identified asrequiring further research.

Project Background

One challenge in deepwater drilling is the narrowing of the pore pressure/fracture gradient margin,mainly due to the decrease of fracture gradient as water depth increases. This means more casingstrings, shallow casing points, longer and heavier drilling risers and bigger and more expensive rigs.

To dat e, several variants of MPD systems have been used. This art icle focuses on DGD achievedby mechanical lifting, which is a new technology as far as operation and maintenance data areconcerned.

When developing classif ication and safety requirements for a novel technology, ABS adopts thefollowing evaluation methodology:

1. Develop an understanding of the concept;

2. Identify the novel aspects of the proposed design;
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Figure 2: The DGD system produces a largerdrilling window compared with a single f luid

conventional system, and therefore requiresf ewer casing st rings.

3. Identify the hazards and safety concerns arising from the concept and f rom the specific novelfeatures;

4. Identify existing marine and offshore requirements and standards and conduct a gap analysis;

5. Use the gap analysis to identify t hose areas of the design for which no relevant marinestandards currently exist; and

6. Apply first principles design and risk methodologies to assess the risks.

This approach has been fo llowed in the evaluation of the DGD concepts that were presented toABS in request of Approval in Principle (AIP). When developing rules, ABS places paramountimportance on promot ing safet y of life, property and the natural environment. Thus, the primaryfocus of this art icle is on the safe application of DGD equipment and not the optimization of thedesign, with respect t o ef f iciency or return on investment.

FMECA and what-if analyses are carried out on the DGD system and its equipment at afunctional level to determine safety and environmental risks. The next step, which is outside thescope of this art icle, is to determine possible measures to eliminate, mit igate or reduce theidentified risks.

DGD Overview

As new reserves are explored in ultra-deepwaters,the capability limits of current risers are beingapproached. The long riser strings required forgreater water depths may experience significantstresses due to vibrat ion. Deepwater drilling involvesa narrower drilling window due to deepwateroverburden, where a very narrow margin betweenpore pressure and fracture pressure profiles exists.

Thus, maintaining the hydrostatic pressure on themud line becomes a challenging design and seriousoperational issue. The alternate technology is touse a riserless mud recovery (RMR) and DGDsystem.

Dual gradient uses two hydrostatic gradients the seawater gradient f rom sea surface to seaflooto manage the borehole and the mud gradient f rom the sea floor to prevent the borehole fromcollapsing and removing cutt ings from the borehole (Figure 1). Thus, the mud return does not gothrough a conventional large-diameter drilling riser. The separate mudlift system uses a return linethat is powered by subsea pumps.

In a static condition, the bottomhole pressure is balanced by the hydrostatic pressure. In dynamiccondition when the mud is circulating the hole, the bot tomhole pressure is a function ofhydrostatic pressure and t he annular friction pressure.

The two limit ing pressure gradients are pore pressure and fracture pressure. As seen in Figures 1and 2, the DGD system provides a larger drilling window compared with a single fluid convent ionalsystem, thus requiring fewer casing strings.

With DGD, the bot tomhole pressure is achieved using a combinat ion of two f luids seawater andheavy mud. The drilling rig can be said to be effectively on the seabed as the water depthoverburden is balanced by the seawater line gradient (Figure 2).


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This helps to better manage the margin between pore pressure and fracture pressure, signif icantlyreducing the number of casing strings that would have been required if a single fluid (mud) wereused to reach the bot tomhole pressure and avoid lost circulation.

The DGD system requires addit ional equipment subsea, as well as on t he rig. Thus, two systemintegrations must be considered. One is the subsea integration involving pump, drill string valve(DSV), subsea rotating diverter (SRD) on the BOP, etc. The other is the rig integration involvingsurface pumps, dual trip tanks, strengthened cellar deck, additional cont rols, etc. The latter is out

of the scope of this art icle.

Offshore Regulatory and Safet y Regime

Offshore regulatory regimes focus on safety and are applied through many layers, ranging f romthe international level, which facilitates and regulates global safet y goals, to class societies thatdevelop and publish rules and guides for structural and mechanical integrity of the complete marineand/or offshore structures, to industry codes and standards that also provide requirements formechanical integrity of specif ic equipment or components.

To protect the interests of their territorial waters, local jurisdictions also institute regulations toensure safety. Finally, the maritime vessels or of fshore structure owners/operators also haveestablished their sets o f technical, operating and maintenance requirements to ensure safeoperation and protect t heir capital assets.

Novel Concept Approval Process

The ABS review of novel concepts follows three stages: (1) Conceptual design and AIP; (2)Detailed design and const ruction, and issuance of ABS class approval; and (3) Operations andmaintenance of class. The AIP stage deals with the risk-based approval process and requiressubmittal of conceptual engineering and risk assessment studies. The final class approval stagerequires submission of detailed risk assessments. Figure 3 shows the process that ABS and theclient f ollow to achieve these milestones.

The ABS Guidance Not es describe the use of qualitat ive and quantitative risk assessment too ls toidentify t he hazards and assess the risks introduced by the novel features, operability and anyinterface issues with o ther systems. The t oo ls commonly employed range from qualitat ive hazardidentification tools (for example, What-If, HAZID, HAZOP, FMECA), a fully reliability-basedapproach to demonstrate the functionality and achieved margins of safet y, a deterministicapproach t o assess consequences of failures, or a semi-probabilist ic approach to assess thesensitivities and variability of key design parameters.

The Guidance Notes also discuss a comparative risk assessment (qualitative or quantitative)where the risk levels are compared with risk levels of ot her systems instead of absolute criteria.

The f inal class approval stage requires submission of detailed risk assessments, which may besupported by tests. The detailed risk assessments are intended to quantify risk and uncertaintiesin more detail for t hose hazards ident ified as high risk in the conceptual risk assessment during theAIP stage.

FMECA for DGD s stem


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Table 1 lists the DGD functions and relatedequipment t hat were st udied during this

project.

A failure mode effects analysis (FMEA) is astructured approach for ident ifying means of failureand the effects on a local and global basis. Theobjective is to determine whether a failure mode canoccur, and if so, whether an unsafe or inoperablecondition could result .

An FMECA is an extension of the FMEA andincludes a criticality analysis, which is used to chartthe probability of failure modes against the severityof their consequences. The result highlights failuremodes with relatively high probability and severity ofconsequences, allowing a design improvement (orremedial) effort to be directed where it will producethe greatest value. The criticality ranking mayinclude the failure detection capabilities present inthe design.

For t he evaluation of DGD equipment failure mode criticality, severity ranking was done on a 1-t o-

10 scale based on t he safety and environmental implications and t he downt ime incurred beforegett ing back into operation. The occurrence f requency was ranked on a 1-to-10 scale based onthe expected failure frequency.

A limiting value of one failure in five years was assumed as the worst frequency. This assumptionis based on the planned API 53 standard,which states, At least every f ive years, the well cont rolsystem components shall be inspected for repair or remanufacturing, in accordance withequipment owners PM program or the manufacturers guidelines.

The failure detect ion capability was ranked on a 1-t o-10 scale based on t he available designcontrols and maintenance tasks available to predict the failure. An FMECA study performed during

the design phase identif ies the equipment and systems to which the maintenance activities shouldbe concentrated during the development of a preventive maintenance programs (PMP).

At different st ages of the operat ional life, an FMECA would also identify the failure historyobserved for the equipment and thus help in updating the maintenance philosophy andprocedures. FMECA further helps in ident ifying functional failures and avoiding any single-pointfailures.

An FMECA study can be performed by a functional approach or a hardware approach. Thefunctional approach is used to analyze the system and sub-system effects. This approach toFMEA was adopted for t he study of DGD. These approaches help in tying the equipment to

functional failures and to avoid single-point failures.

In the hardware approach, equipment components are represented in a block diagram, and thetheory of operation and assumptions are writ ten down. The FMEA following a hardware approachwill be a detailed analysis down to each component level. This approach helps in detailed spare-parts analysis, updating preventive maintenance programs, etc. However, a greater level of detailfor the equipment, operation and maintenance plan should be present for this type of study.

The funct ional-level FMECA stud for the dual-


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Figure 3: The process to approve novelconcepts includes conceptual design andapproval in principle, detailed design andconst ruction and issuance of ABS class

approval, and operations and maintenance ofclass.

gradient system identif ied the following:

Credible failure modes applicable to eachequipment item or grouping of equipment;

Effects of the failure on overall operat ions and,where applicable, local and overall ef fects on thedrilling unit;

Foreseeable causes for each failure mode;

Safeguards in place to detect, prevent or mitigateeach failure;

Recommended actions t o address failure modesthat, as judged by the FMECA team, are notadequately safeguarded; and

Criticality rankings for each failure mode.

Some of the functional failure modes assessed during the FMECA study were:

No seawater to power the mudlift pump or reduced flow due to clogging upstream;

Loss of control on subsea pump hydraulic valves (only reciprocating type of PDP);

Subsea pump hydraulic valves malfunction (only reciprocating type of PDP);

Total loss of mudlift pump performance;

Reduction of mudlift pump performance (degraded mode of operation);

Subsea pump installation integrity compromised;

Subsea pump valves partial or tot al obstruction (only reciprocating type of PDP);

SRD unable to divert mud and cuttings to subsea pumps;

Drill string valve malfunction; not closing during pipe connections or circulation stop;

Drill string valve malfunction; remaining totally or partially closed after pipe connections atcirculation restart and/or during drilling;

Subsea pump valves plugged (only reciprocat ing type of PDP);

Subsea pump plugged by cutt ings;

SPU plugged by cutt ings;

Subsea pump stops working;

Reduced f low volume or no f luids coming f rom suction module (SMO);

Fluctuat ions and/or reduction on subsea pump output (centrifugal pump);


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Stop of f low through subsea pump (centrifugal pump);

Fluctuat ions and/or reduction on subsea pump output (degraded mode; only piston pump);

Cross-sectional area reduction of subsea pump suction line;

Partial or total subsea pump suction line fluid leak;

Partial or total subsea mud return line fluid leak;

Part ial or tot al plug of SMO bowl by hydrates;

SMO instability due to bad installation;

Subsea pump induced pressure pulsat ion in piping/lines with cyclic stress inducing fat igue witheventual lines connection failure (only reciprocating type of PDP);

Subsea pump impeller failure (centrifugal pump);

Part ial or tot al loss of the subsea pump monitoring sensors;

CCS pipe ram activation failure;

CCS blind ram activation failure;

CCS chamber pressurizat ion f ailure;

Mudlift pump discharge of surface seawater layer to deepwater environment causing pH, oxygenand nutrients changes around wellhead; and

Excessive noise around wellhead affecting deepwater marine life.

What-If Analysis

A What-If analysis is a brainstorming approach that uses broad, loosely structured quest ioning topostulate potential upsets that may result in mishaps or system performance problems, andensure that appropriate safeguards against those problems are in place. This technique was usedto supplement the FMECA study and to cross-check if possible failure modes and deviat ions havebeen addressed and the safeguards identified. For the DGD system, the following set of potentialproblems that could arise was generated using qualitative descriptions:

What if mudlif t pump stops working?

What if seawater supply to the mudlif t pump stops but hydraulic valves is st ill working?

What if subsea pump valves synchronism is uncont rollable?

What if one or more subsea pump valves stop?

What if subsea pump starts to show low performance?

What if subsea pump completely loses its performance?

What if subsea pump valves are blocked?


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What if no f luids are coming f rom subsea pump suction line?

What if SPU (when present) is plugged by cuttings?

What if subsea pump installation is compromised?

What if the mud return line breaks?

What if the U-tube eff ect cannot be controlled?

What if subsea pumps monitoring/cont rol sensors fail?

What if CCS fails during a pipe connection?

Technology Evaluation

Based on the evaluat ions and the reviews of the design concepts, the authors have identif ied thefollowing elements, including typically associated t ypes of hazards, as posing the greatest risks tolife, property and the environment in the drilling application of the DGD system.

The hazards related to accidents such as uncontrolled blowout s and emergency disconnectprocedures are out of the scope of this art icle.

Wellbore fluids discharge to sea

Compared with a conventional pump and dump system, DGD allows the use of drilling f luids withhigher density and more appropriate chemical composition. But the risks related to discharge ofwellbore f luids (i.e., combination of drilling f luids, cutt ings and, when present, oil and gas) becomehigher. From this perspective, any leak on t he return system f rom the wellhead to the surface canhave a direct impact on the environment. The most crit ical situation is the one where a physicalbarrier (e.g., blowout preventer and drill string valve), used to preserve the wellbore integrity, is notpresent on the system and the leakage happens between the wellhead and subsea pump.

An example of such a crit ical situat ion is the riserless mud recovery (RMR) system used to drill thetop-hole sect ions where only an SMO is installed on the seabed. The top of the SMO is composedof a bowl where wellbore fluids are in direct contact with the seawater. During normal operationswithout t he presence of gas, those fluids are not mixing with seawater due to the densitydifference between them, and they are kept inside the bowl by the action of the subsea pumpflow.

It was identif ied that there can be discharge of wellbore f luid and cutt ings to t he sea from theSMO bowl caused by:

A cutt ings-generated obstruct ion (or plug) of the subsea pump and/or the line from the bowl tothe pump;

An unplanned subsea pump stoppage due to a lack of power or umbilicals failure;

A mechanical failure of subsea pump due to vibration, cavitation, erosion corrosion, wear of therotating parts (when applicable), pressure pulsation and stress fluctuations on pump impeller;

A pump blockage due t o an excess of gas inside the pump (i.e., gas lock, in the case ofcentrifugal pump);

SMO loss of stability due to poor installation or caused by seabed subsidence, shallow hazards,


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seabed liquefact ion, underground blowout ;

A rupture in line (or connection) from SMO and subsea pump (in this case, the leak will be at SMObowl and at rupture point); and

An overpressure not cont rollable by subsea pump flow.

Other DGD conf igurations diff erent from the one that was evaluated can also have accidentaldischarge of wellbore f luids to t he sea:

Af ter a loss of containment o f a subsea pump component;

Af ter a loss of containment of SRD (when present) and/or SPU (when present);

After any loss of containment of return line and/or connections from wellhead to surface;

Af ter a loss of containment of mudlif t pump elastomer (or elastomers), the failure can putwellbore f luid and cutt ings in contact with the seawater used to power the pump. This water isnormally discharged to the sea, and the seawater will be contaminated with f luid and cutt ings; and

Af ter a loss of containment of the riser between the BOP and the subsea pump. This can happenin a post -BOP section when subsea pump is not close to t he seabed and part o f the riser act asreturn line.

On all DGD system conf igurations, when a leakage happens on the section between the wellheadand the subsea pump, backpressure will be applied to the wellbore and, without the presenceinside the bot tomhole assembly (BHA) of a DSV (or with a DSV damaged), the backpressure willcontinue even after a stop in circulation, until equilibrium is reached. This U-tube effect will alsoappear in a normal pipe connect ion with all pumps of f , including subsea pumps, if a DSV is notinstalled or is damaged. This situation highlights the importance of a reliable DSV as an additionalphysical barrier to enhance the safety of the operations.

Maintenance and Inspection of subsea components

On a DGD system, subsea pumps, DSV, SRD (when present) and CCS (when present, installed onrig floor) are together with the drilling fluid column, all part of a physical barrier system. It wasidentified that a loss of performance or a failure of this equipment can trigger a loss of cont rol onthe fluid column, putting the well integrity and drilling operation in danger. These failures can creepin during the design phase and can also happen during the drilling phase:

A f ailure mode that originates during the design and planning phase, i.e., poor DGD systemconfiguration (e.g., subsea pump type, position, return line type, chemical inhibitors, etc) notsuitable to local field conditions (e.g., seabed, water depth, metocean condit ions, shallow hazards,

drilled cutt ings behavior during circulat ion, expected gas content inside drilling fluid, etc); and

Failure during execution phase (drilling).

In general, the design of subsea equipment must take into consideration t hat the equipment mustwork fo r long periods with limited opportunit ies for maintenance and, in a deepwater environment,it must allow remotely cont rolled vehicles (ROV) to at least perform basic rout ine repairs. A soundprecision maintenance st rategy can avoid potent ial failures creeping in during the init ial phase. It isalso seen from previous industry research that preventive maintenance addresses onlyapproximately 15% of failures. Thus, scheduled maintenance/preventive maintenance programscannot be enough to prevent failures. In such cases, cont inuous monitoring is a priority f or sound


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equipment management. A targeted condition-based monitoring (CBM) should be applied, inaddition to a preventive maintenance strategy, because it improves equipment reliability and helpsto def ine the right t ime for proper maintenance.

On DGD, one of the most important pieces of equipment is the subsea pump because it is thisequipment that makes the real difference between a conventional of fshore drilling system and aDGD. A CCS (when present) is also a critical system and transforms a DGD into a real MPD systemAny loss of cont rol on the subsea pump and/or CCS can generate a serious wellbore integrityissue. CBM can be applied at least on some critical components of subsea pumps and CCS.

In general, a CCS is used for the purpose of leaving the bottomhole pressure as close as possibleto pore pressure. A failure of CCS can lead to a reduction of bot tomhole pressure to below thepore pressure. This underbalanced situat ion, also depending on the presence of DSV, can becont rolled through a proper subsea pump f low change (or stop), compensating for the bot tomholepressure loss; otherwise, it can become uncontrollable with t he need to activate the BOP. TheCCS components that can be monitored are identif ied as:

Blind ram: An important device of the CCS allowing for a continuous circulation during pipeconnection; a seal failure can force a stop in circulation due to surface mud losses;

Pipe rams: A seal failure can generate pressure equalizat ion before disconnect ion; and

Valve system that cont rols the pressurization chambers: a wrong pressurization (pressure toohigh or too low) during pipe disconnect ion can lead to a wellbore integrity issue.

The following subsea pump components were considered as critical equipment that can be placedunder a CBM strategy:

Valve system of reciprocat ing type of PDP (i.e., subsea mudlif t and piston pumps): The correctsynchronization between valves must be maintained by hydraulic control, and the valves musthandle different solid sizes and resist wear and corrosion. In deep and ultra-deep waters, valves

must be pressure-compensated;

Mudlif t pump elastomer: It can be subjected to mechanical and thermal fat igue, chemical andaromatics att ack during its working life;

The mechanical parts and seals of the piston/cylinder system of piston pump; and

The RTP (i.e., centrifugal pump and disc pumps) mechanical parts that can be subjected t othermo-mechanical fat igue, wear, cavitat ion, erosion corrosion and f atigue corrosion.

The subsea pump can affect the life of equipment connected to it due to diff erent kinds of f low-induced vibration. One such eff ect is the pulsat ing flow of PDP that, in theory, can induce

lines/pipes cyclic loading and damage the pipes/lines connect ions. The RTP can also generateunsteady flow due to the drilling operation itself (e.g., excess of cuttings, drilling fluid behaving as amult iphase flow due to presence of gas, etc).

In addition, the return line, even if designed to handle the water-depth pressures, corrosion,currents and waves, must be closely monitored. Hence, CBM must be applied to t he mud returnline, in particular on connections with higher stress at subsea pump out let/inlet and at topsideterminat ion that, depending on installation, can be subjected t o mult i-axial fat igue and corrosion.

Proper Staffing and Training


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For a successful DGD operation, personnel must have a comprehensive understanding of allconcepts of the DGD system and its impacts on drilling operations. In addition, personnel must beable to make real-time decisions. They should be consistent when communicating, have clearresponsibilities and have procedures in place to handle unexpected situations in a controlled wayto reduce the consequences. Continuous t raining is a way to achieve these object ives.

Further research or tests

The following are the issues recommended for f urther research:

Pumping elements of subsea pumps: One of the most crit ical parts of a subsea pump on a DGDsystem are the pumping elements (e.g., elastomer, piston, impeller, etc.). This is mainly due to thefact that they need to handle wellbore f luids. An improvement of actual pumping element materialwill certainly bring more reliability to t he system;

Impact of seawater exchange and global application: Some PDPs (i.e., mudlift and piston pumps,also called ram pumps) are powered by seawater that is pumped f rom surface down to theinstallation and discharged to the sea. In deepwater and ultra-deepwater wells, there are concernsregarding the effects of such circulation systems on marine life, in part icular for a f ield with closelyspaced and long wells with high pump working time.

The seawater pumped is normally coming from the surface close t o the support vessel, and thedischarge is supposed to be close to the subsea pump.

The seawater chemistry (i.e., oxygen and CO2 content, pH, etc) changes in space, depth and time

in dif ferent ways all over the planet; and the impact of mixing such layers needs to be evaluated,integrating information regarding pump discharge flow, local oceanographic and biological data;

Noise impact of subsea pump operation: In an ultra-deepwater environment, the noise generatedby a subsea pump can impact marine life, in part icular for a f ield with closely spaced and long wellswith high pump working t ime. For example, low-f requency sound can be audible for considerable

distance. The impact of this noise on marine organism behavior can be modeled during the designstage and steps taken to reduce the impact.

Logging while drilling (LWD): A drilling BHA includes LWD that , in general, are sending real-t imedata through pressure pulses on the fluid column. Although LWD is out of the scope of this article,it is worth mentioning that a DGD system that intends to drill an entire well should consider howLWD tools will be used. Subsea pumps can generate addit ional pressure noise inside the f luidcolumn, partially or tot ally masking LWD pulses.

Alternatively, two t ypes of telemetry systems can help to avoid this kind of problem because theydo not need the f luid column for data t ransmission electromagnetic and wired drill pipe telemetry

The choice of a correct type of real-t ime data transmission will be crucial for the success of a DGDoperation.

ROV intervention capability and interfaces between t he ROV and the crit ical subsea equipmentneed to be assessed to identify technology gaps;

Theoretically, it is possible to use a casing-while-drilling or monobore technology during a DGDoperation. All possible issues must be assessed;

Some post -BOP systems do not contemplate the use of SRD, and the mud returning fromwellbore annulus is contained above the BOP inside part of the riser. Mud level is cont rolled by thesubsea pump f low rate and limited to the subsea pump position above the BOP. Any loss of


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control of the mud level can put the operation at risk (e.g., uncontrollable gas in the riser). Animprovement of such systems will certainly improve the safety of the operations; and

Rig integration: Apart f rom the subsea equipment for DGD, many modifications need to becarried out on the rig floor and control panels. Rig integrat ion was not in the scope of theassessment, but issues can be out lined as below, though they are not limited to t he following, andmust be addressed in the risk management plan:

Cellar deck and BOP bridge crane modification: The addit ion of mudlift pump weight to the BOPand lowering it in the water from the moonpool will require adequate strengthening of the deckand the BOP bridge crane;

Dual trip tanks: The addition of one more tank because two separate volumes (riser volume andmud volume) are to be managed;

Mud return line;

Seawater supply line to seawater f ilt ration skid;

Seawater filtrat ion skid;

Seawater power line;

Additional occupied space for subsea mudlift drilling team;

Control panel modif ications; and

Other related electrical integration issues.

Conclusion

Risk-based classification is a project-specific criterion. The techniques and methodologies

employed vary from project to project. The existing prescriptive rules are considered a benchmark,and any risk-based approach to classif ication should, as a minimum, provide an equivalent level ofsafety to the prescriptive rules. A risk-based approach to classif ication focuses the engineeringand survey act ivit ies on t he systems and components with the highest-identified risk and theidentified act ions to mit igate the risks.

A successful risk-based evaluation will also require a proper risk management plan (RMP). For theDGD system, an RMP should describe the integrated approach to demonstrate the equivalent leveof safety using risk-based techniques targeted at t he subsea and rig installations, the cont rolsystems and the risk management aspects. The RMP should be treated as a living document as itis intended to be an integral part of risk management. Development of the RMP should address

hazard ident ification, risk responsibilities, risk analysis and assessment, risk mitigation andrevalidation of risks.

From the evaluations undertaken to date, the authors have identified various aspects of the DGDtechnology that may pose an increased level of risk and should be addressed during the earlystages of design development. Appropriate analysis and studies should be performed to assist thedesigner to understand the resulting consequences associated with these hazards and risks.

Risk-mitigation techniques including the redesign of identified and specifically targetedcomponents or equipment to improve reliability, and, therefore, the probability of failure should beadopted for high-risk items.


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This is an area of future study for specif ic equipment in a DGD. Further, these findings do notnecessarily reflect t he ABS viewpoint and are solely those of the authors based on the systemthey studied.

References

1. ABS. (2003). Guidance Notes on Review and Approval of Novel Concept s. Houston: ABS.

2. ABS. (2011). Guide for the Classifif cation of Drilling Systems. Houston: ABS.

3. API. (2010). Isolat ing Potential Flow Zones During Well Construction, Recommended practice65 Part 2. American Petroleum Institute.

4. API. (2011). RP 96 Deepwater Well Design and Const ruction. American Petroleum Institute.

5. API. (unpublished). Blowout Prevention Equipment Systems for Drilling Wells, API Standard 53

4th edition second draft for balloting.

6. Dowell, D., & Smith, T. (n.d.). A Deepwater Breakthrough: The Launch Window for DualGradient Drilling Technology. Retrieved March 2012, fromhttp://www.pacificdrilling.com/Company/Education-Center/default.aspx

7. Malloy, K. P. (2011). Risk Prof ile of Dual Gradient Drilling: BOEMRE Technology Assessmentand Research Program. US Department of the Interior.

8. Patel, H., Pham, M., Korn, M., Walters, P., & Das, B. (2011). Safety Enhancement to OffshoreDrilling Operations. Offshore Technology Conference. Brazil: OTC.

9. Scanlon, T. (2011). Environmentally-Improved Method of Drilling Top-Hole Sections OffshoreBrasil Using Dual-Gradient Drilling Techniques for the First Time in Brasil. Of fshoretechnology Conference. Brazil: OTC.

10. (url). Retrieved March 2012, from http://www.pmel.noaa.gov/vents/acoust ics/tutorial/11-sofar.html

11. (url). Retrieved March 2012, from:http://www.nov.com/Drilling/Drilling_Pressure_Control/Continuous_Circulation_Systems.aspx

12. (url). Retrieved March 2012, from ht tp://sam.ucsd.edu/sio210/lect_2/lecture_2.html

13. Sondalini, M. (2004). How to use Condit ion Based Maintenance Strategy for EquipmentFailure Prevention. Lifet ime Reliability Solutions Consultant s. (url). Retrieved April 2012, fromhttp://www.lifetime-reliability.com/free-articles/maintenance-management/condition-based-maintenance.html

14. Neelamkavil, J. (2009). A review of existing too ls and their applicability to f acility maintenance

management RR-285. National Research Council Canada.

This article is based on a presentation at the IADC Advanced Rig Technology Workshop, 12 June2012, Barcelona, Spain.

Acknowledgement: The authors would like to thank Todd Grove, VP technology, ABS; SudheerChand, director of offshore technology, ABS; and Bret Montaruli, VP offshore technology, ABS, fortheir constant support during the project and helpful insights during peer review of this paper.

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