chap2

EP 2002-1500 - 8 - Restricted to Shell Personnel Only

2. ORGANISATION OF WELL CONTROL OPERATIONS

2.1. Personnel Responsibilities

Well control operations may involve many individuals working as a team. Theresponsibilities of each individual must be clearly defined and they must have the trainingand skills to enable them to perform their allocated duties. This section gives examples ofhow various responsibilities may be assigned.

2.1.1. Person In Charge of Well Control

It is imperative that this Person In Charge is clearly identified before operations commenceand that he is totally aware of his duties and responsibility to ensure that operations areconducted in a manner to provide for complete well control. The deputy and stand-in tothe Person in Charge should also be clearly identified. This responsibility for the executionof well control operations may lie with the Shell or Contractor Representative as laid out inCompany procedures consistent with Government Regulations. The responsibilities of thePerson In Charge in no way reduce those of other supervisory staff with regard to wellcontrol.

Pre-Kick

• Duties may include:

• Ensure that any conflict of policy is resolved;

• Ensure that policies are followed, instructions are properly given and to make surethat they are fully understood and effectively implemented;

• Acquaint himself with the locality in which he is drilling;

• Review the drilling programme in detail;

• Advise his supervisors of any aspects of the prognosis or well plan which may causethe loss of well control and take appropriate action to avoid such events;

• Maintain a system of well control data sheets to be ready for immediate use ifrequired;

• Ensure that units (SI or field units) are used consistently throughout the drilling rigand be consistent with the drilling programme;

• Check on the adequacy of well control training of supervisory staff on site andrelevant personnel on the rig floor;

• Ensure that all operations conducted with equipment associated with pressurecontrol are carried out in a safe and efficient manner;

• Be acquainted with the contingency plans relating to fire, blowout, pollution andspillage on or around the location;

• Include a full knowledge of H2S procedures in areas where a possibility of H2Soccurrence exists and to verify that all contractors on site are suitably equipped andtrained;

• Organise regular kick and other well control drills and report crew performance;


• Delegate duties and responsibilities as required.

Post Kick

• Once the well is shut-in, to organise a pre-job meeting with all key personnelinvolved in the well control operation and provide specific well control procedures;

• To monitor and supervise the implementation of these procedures;

• To be present on the drillfloor at the start of well control operations (either the ShellRep or the Contractor Toolpusher to be present on the drill floor for the duration ofthe operation).

• Maintain communication with the Operations Base;

• Assign the responsibility of keeping a diary of events;

• Produce reports as required by local procedures or regulations.

2.1.2. Contractor Toolpusher (if not the Person in Charge)

• Overall responsibility for implementation of the well control operation;

• Must ensure Driller and crews are correctly deployed;

• Must be present on the rig floor at the start of operations;

• Must facilitate an optimum crew handover during well control operations.

2.1.3. Driller

• Responsible for detection of kicks and losses;

• Responsible for making the well safe;

• Responsible for implementing agreed contingency procedures.

• Responsible for notifying Contractor & Company representatives at the earliestopportunity.

• Responsible for supervising the crew during well control operations.

2.1.4. Mud Engineer

• Responsible for maintaining the mud condition.

2.1.5. Cementer (if present)

• Must ensure the cement unit is ready for operation.

2.1.6. Mud Logging Engineers (if present)

• Co-responsible (with Driller) for initial kick detection;

• To monitor and record all parameters during the well control operation, including;

� Time

� Shut-in pressures


� Pump strokes (total and SPM)

� Pump pressure

� Casing pressure

� Gas

� H2S

� Pit volumes

• Keep a full and detailed record of the operation.

2.1.7. Early Kick Detection Engineers (if present)

• Responsible for monitoring inflow/outflow at all times;

• Responsible for notifying the Driller in the case of a differential flow alarm.

2.1.8. Subsea Engineer (where appropriate)

• Must be available for consultation at all times during any well control operation;

• Responsible for supervision of Subsea BOP system operation.

2.1.9. Well Service Supervisor

During workover or well intervention operations, the status of Person In Charge may bedelegated to the Well Service Supervisor. Well control may differ from drilling in thatactivities may involve snubbing units, slickline, electric line or coiled tubing and operationsare often on a live well. His duties will be to:

Pre-Kick

• Ensure all pressure control equipment is fit for purpose and properly rigged up andpressure tested;

• Interface between contractor, company and 3rd party personnel;

• Ensure all check valves etc. required for pipe/tubulars in use are available;

• Ensure adequate stocks of brine are available if required;

Post Kick

• Coordinate all service personnel involved;

• To calculate kill parameters;

• To supervise well kill;

• Produce a kill report if required.

2.1.10. Other Roles

Other operations including marine and logistics associated with a well control situation arenot detailed in this manual and should be included in relevant contingency procedures.


2.2. Well Planning for Well Control

Successful execution of well control operations is highly dependent on thorough planning.This section deals with issues related to well control that must be addressed in the wellplanning stage.

2.2.1. Introduction

Well control is an integral part of the well planning process, be it for a new well or a re-entry. The drilling programme will cover well control risks in detail

These risks and subsequent mitigation will focus on keeping the well under control duringall phases of the operation. To be successful, subsurface conditions must be predicted,detected, and controlled.

Consideration must be given to;

• the potential hazards to be encountered;

• uncertainties related to formation parameters;

• maintaining Primary Control;

• the equipment to be used;

• the procedures to be followed;

• training of the crew.

Advance planning should include an equipment and operations procedure checklist. Theitems on the checklist will depend on the prognosed hazards, company policies,government regulations, and anticipated use of the well control equipment. Any specificoperating practices / procedures / recommendations should be included in the drillingprogramme. The first step is to assemble the available data, then evaluate the informationand predict what hazards can be expected. The well programme should provide the meansto manage the risks of these hazards to ALARP (as low as reasonably practical) andmitigation steps (contingency plans) should be in place to deal with them should anyescalation or different circumstances be experienced.

2.2.2. Predicted Conditions

The well casing and tubing programme will have been designed in compliance with theShell Casing and Tubing Design Guide. Any well control assumptions used inprogramming operations must be consistent with those used in that design.

Data Availability and GatheringMost Operating Companies will have agreed minimum data requirements as input into thewell planning process. The following types of data are typical minimum of what is requiredand include but is not limited to;

� Bathymetric surveys including information on existing structures

� Seismic information and interpretation, including shallow gas surveys;

� For re-entry, existing Well Status/Integrity and proximity of other wells;


� Offset lithology, porosity, permeability, stability and information on previous drillingproblems etc.;

� Identification of weak formation or loss zones;

� Formation fluid type, hydrocarbon depths, gas zones, H2S, CO2;

� Data gathering requirements (DST, Logging, mud logging, coring etc.)

� Other subsea or surface hazards such as mobile salt formations, water flows etc.;

Formation PressureAll available engineering, geophysical and geological information should be analyzed topredict formation fracture gradients, pore pressure, and shallow hazards. Offset well datamay help indicate the possibility of charged or depleted formations.

From pressure profiles developed plans can then be prepared for handling under and over-pressured formations, both shallow and deep. This pressure and formation strength dataare fundamental to the design of the drilling programme, drilling fluids required, casingstrings, and selection of best operating practices.

Casing ProgrammesCasing programmes in offset wells, offset fields, and regional wells, combined withgeological and formation pressure data, are essential in planning a well. The casing design isonly valid for formation strength and pore pressure assumptions used in planning the well.The casing design may need to be revalidated should unexpected changes occur.

When work is to be done on an existing well the condition of the casing will need to beassessed And any worn or corroded casing should be downgraded using techniquesdetailed in the Shell Casing and Tubing Design Guide.

Drilling Data UtilisationA number of methods or indicators can be used to detect abnormal pressure while drilling,these include but are not limited to:

� drilling rate or 'd' exponent;

� sloughing shale;

� shale density;

� gas units in drilling fluid;

� drilling fluid properties;

Formation strength leak-off/limit tests should be included in the programme. Theimportance of gathering pressure and strength data whilst drilling cannot be overstated.Wireline formation tests provide reliable direct pressure measurement and should beconsidered for critical wells.

2.2.3. Primary Well Control

Drilling fluid of suitable density and volume to maintain an overbalance on formation porepressure is necessary to maintain primary control.

Maintenance of OverbalanceThis overbalance can be effected by drilled solids and/or influx of fluids. For this reasoncontrolled drilling rates are advisable in certain cases where fast drilling is possible or the


amount of overbalance is critical. The use of a PWD tool can assist in accuratedetermination of dynamic BHP.

Underbalanced DrillingThis is a specialized application used where conditions are well known, predictable andrisks can be managed. In this case Primary well control is achieved with a combination ofdrilling fluids (may be near-balance or underbalanced) and a rotating BOP. Contingencyplans to return to an overbalanced situation should normally be in place in case ofproblems.

Drilling Fluid Monitoring EquipmentIt is essential to monitor the quality and quantity of drilling fluid in the system. Measuringdevices that will monitor the active surface and down-hole drilling fluid volumes should beprovided. Several methods of combining different types of equipment can be used,depending upon the well requirements. These may include:

� pump stroke counters;

� flow line sensors with alarms;

� pit level recorders with alarms;

� trip gain-and-loss meters;

� trip tanks.

� flow meters, particularly for Slim hole kick detection;

� PWD

Quality of drilling fluid is extremely important. Provisions should be made to measure thedensity, viscosity, and other fluid properties as required. A mud logging unit may also beemployed to monitor these and other pressure indicating parameters mentioned above.

Fluid Storage CapacityAdequate supplies of fluids are necessary for well control operations. Logistics and storageshould be thoroughly reviewed and planned, especially offshore where space on a drillingrig or platform is limited. Priority should be considered for storage of adequate supplies ofbase fluids, weighting material, and lost circulation materials. Procedures and fluid recipesshould be pre-planned and readily available. It may be desirable to have kill weight or LCMfluids pre-mixed and available during certain operations such as drilling into a suspectedshallow gas formation or a transition zone. In floating drilling operations, plans should bemade to recover and store riser fluids during planned and emergency disconnects,especially when using oil or synthetic based drilling fluids and certain heavy brines.

Service OperationsWell intervention or service operations need to be planned in a similar manner to any otherwell operation. These include, but are not limited to: logging, coring, fishing, drill stemtesting, slick-line, and coiled tubing operations (refer to API RP 5C7: Recommended Practicefor Coiled Tubing Operations in Oil and Gas Well Services). Considerations for all theseoperations include:

� Procedures for securing the well;

� Monitoring well fluid levels when in and out of hole;

� Avoiding surge and swabbing;


� Procedures for stuck pipe and /or fishing operations;

� Contingency plans in case of problems;

2.2.4. Blowout Prevention Equipment Selection

A blowout prevention equipment system comprises all the equipment componentsrequired for well control. These systems include BOPs, choke and kill lines, chokemanifold, degassers, flare lines, closing unit, marine riser (if applicable), and any auxiliaryequipment. Their primary function is to confine well fluids to the well bore, provide meansto add fluid to the well bore, and allow controlled volumes to be withdrawn while allowingcontrolled pipe movement. The selection of equipment for a particular well is dictated bymany factors including, but not necessarily limited to, casing and drill string design,anticipated pressures, environment, space, governmental regulations, and availability.

Following are some general guidelines:The rated working pressure of ram-type BOPs should exceed the maximum anticipatedsurface pressure. Provisions should be made for closing BOPs on all sizes of drill pipe, drillcollars and casing that may be used.

Schematic drawings should be available in Drilling Contractor or Operating CompanyDrilling Manuals showing equipment and arrangement of the wellhead, BOP stack, valves,lines, manifold, and accessory equipment required for each hole section. These drawingsshould clearly indicate the location, size, and type of rams. Any changes to these standardsor well specific operational requirements should be detailed in the well programme.

The location of the various rams in the stack-up should be determined after carefulconsideration of the expected use of the stack and application of risk assessment analysis.The rationale behind any changes in ram configuration should be agreed with the drillingcontractor and stated in the well programme detailing specific functions and redundancy.

Whenever possible the BOP type, size and ram confoguration should be chosen tominimise the number of ram changes throughout the drilling or well intervention program.Due to changes in the size of drillpipe in use, or for example the requirement to be able touse a fixed ram to provide blowout prevention during casing running, it may be necessaryto change the position or size and type of a number of BOP rams. When this is necessarygreat care must be taken to provide 2 independent, adequately and correctly tested barriersbetween each potential sources of hydrocarbons.

If hydrogen sulfide is predicted or suspected, materials used in the down hole and surfaceequipment must be resistant to hydrogen embrittlement (sulfide stress cracking). Thefollowing references are recommended:

API RP 7G: Recommended Practice for Drill Stem Design and Operating Limits;

API RP 49: Recommended Practice for Safe Drilling of Wells Containing Hydrogen Sulfide;

API RP 53: Recommended Practice for Blowout Prevention Equipment Systems for Drilling Wells;

API Spec 16A: Specification for Drill Through Equipment; and

NACE Standard MR-01-75: Sulfide Stress Cracking Resistant Metallic Material for Oil FieldEquipment.

Additional considerations for blowout prevention equipment selection are:

• distance between rams so pipe can be stripped, sheared or hung off;


• sizing of lines and valves to minimize friction losses and backpressure during wellkilling operations;

• special marine applications.

Additional information on BOP equipment systems is available in API RP 53: RecommendedPractice for Blowout Prevention Equipment Systems for Drilling Wells (reader should check for thelatest edition). Information on marine riser systems is available in API RP 16Q:Recommended Practice for Design, Selection, Operation and Maintenance of Marine Drilling RiserSystems (reader should check for the latest edition).

2.2.5. Well Control Procedures

Once all the well data are gathered and a general well plan is complete, attention shouldfocus on response to potential well control events during drilling, completion andworkover operations. Procedures must be in place to handle each of the typical situationsshown below. These procedures would normally be expected to be included in OperatingCompany manuals however any well specific requirements which are not covered shouldbe detailed in the well programme.

• Pre-kick data requirements and collection for each stage of operations. This includesadequate surveys to establish the well path and bottom hole position;

• Diverter procedures;

• BOP close-in procedure selection at each stage;

• Kicks while tripping pipe in and out of the hole;

• Kicks while tripping in the hole with casing and liner;

• Kicks while out of the hole;

The details of principles and some alternate recommended practices to deal with theseevents are to be found in this manual.

2.2.6. Shallow Gas

Well proposals should always include a statement on the probability of encounteringshallow gas. This statement should not only use the 'shallow gas survey', but include anassessment drawn from the exploration seismic data, historical well data, the geologicalprobability of a shallow cap rock, coal formations, and any surface indications/seepages.(Shallow gas procedures are discussed in Section 5.3)

2.2.7. Simultaneous Operations

Plans for simultaneous operations may be considered when drilling and workoveroperations are conducted in close proximity with other operations. Examples include: adrilling and production site, an offshore drilling and production platform or jack-upoperations on a producing platform.

Where one installation Management of work system would be employed for more than oneoperation, i.e. wirelining, coiled tubing and drilling from a fixed platform while producingfrom adjacent wells, the operation is often referred to as simultaneous (simultaneous use ofone PTW system). Where a number of installation Management of work systems will be


employed i.e. Jack-up working over a fixed installation, operations are often referred to ascombined.

These combined operations all have additional exposure due to the presence of oil and gasprocessing facilities, pipelines, pipeline connections, and producing wells as well as thepotential for additional production and service personnel. Consideration should be given toshut-in of producing wells and oil and gas processing facilities during certain high riskoperations such as secondary well control, moving the rig, top hole drilling (collision risk),hoisting loads near or above producing wellheads, piping, or process vessels unlessadditional protection has been provided. It is recommended to produce a site specificSimultaneous Operations Plan dealing with interface management and an operationsMatrix, which clarifies which types and levels of activities may be conducted concurrently.An example of a Concurrent Operations Matrix (Shell Expro NBU) is given in Section 2.5.

2.2.8. Well Specific Contingency Issues

While Operating Company contingency plans will need to be in place to cover emergenciesit is essential that the well programme addresses any well specific issues that may impact onmore generic plans. Typical well specific issues that may need to be addressed include butare not limited to;

• Logistics

• Site access/egress in case of emergency and possible relief well site

• Specialised transportation or equipment requirements

• H2S

2.2.9. Training and Instruction

Well control situations, especially those involving shallow gas flows, can develop quicklyand be difficult to detect early. All concerned personnel should be familiar with the wellcontrol system components and installation and be capable of reacting quickly andefficiently to potential situations requiring its use. The following general guidelines areoffered for personnel training and instruction:

• Formal training and instruction in well control theory and procedures isrecommended for all safety critical positions at supervisor and driller levels orequivalent. Contracts should specify competence and training requirements andsystems should be in place to ensure validated certification exists.

• For complex wells where advanced well control procedures are to be followed, welland rig-specific training should be provided based on the procedures established.This is the responsibility of the Operating Company. The following section is forinformation only and describes a number of training schemes currently in useworldwide.

Industry Association Training The International Association of Drilling Contractors(IADC) has implemented two training programmes for industry.

RIG PASS Accreditation System The programme identifies core elements of trainingprogrammes for new rig employees and recognizes programmes that adhere to thoseelements. Completion of a RIG PASS accredited programme confirms that personnel have


met basic requirements defined by safety and training professionals in the drilling industry,irrespective of the rig location.

WellCAP Programme The programme emphasizes the knowledge and practical skillscritical to successful well control. It uses quality benchmarks developed together withoperators, drilling contractors, professional trainers and well control specialists. WellCAPensures that well control training schools adhere to a core curriculum developed byindustry. Accreditation is achieved only after an extensive review of a provider�scurriculum, testing practices, faculty, facilities, and administrative procedures.

International Well Control Forum Accreditation System accepted widely that requiresparticipants to achieve a minimum grade in a written test of their knowledge of wellcontrol principles, procedures and equipment. Formal (re) training is not mandatory forbiannual re-certification. IWCF certification is often set as the minimum acceptablestandard by Governmental Agencies.

2.3. Well Planning Checklist

The following describes details which should be checked and considered during the wellplanning phase. These criteria feed into the Risk Matrix in Section 2.4 and are numberedaccordingly.

2.3.1. Shallow Gas

Every effort should be made to establish the likelihood of shallow gas at the drillinglocation. Typical probabilities would be:

• No evidence of shallow gas;

• Regional observations;

• Locally observed phenomena;

• Shallow seismic anomaly on shot point;

• Oil seeps;

• Seabed pockmarks;

• Observed gas seeps.

2.3.2. Overpressure

The probability of abnormal formation pressure must be investigated at a number of levels:

Geological EnvironmentThe geological setting of the well location may indicate a tendency towards overpressuredsequences. This subject should be discussed with the subsurface team, however typicalproblem areas include

• Currently subsiding basins e.g. Gulf of Mexico

• Significant thickness of recent sediments e.g. Central North Sea

• Adjacent mountains with possible aquifer continuity

• Deep graben features


• Significant thickness of evaporite sequences e.g. Southern North Sea

• Observed halokinetic effects (i.e. salt domes with possible dolomite rafting) e.g.Southern North Sea

• Compressional tectonics e.g. Columbia

Subsurface GeologyGeological hazards which may impact well control should be assessed as thoroughly aspossible from offset data. Typical hazards may include:

• Thief zones � loss of drilling fluid and therefore primary control

• High ratio of shale to sand in sequence � may result in trapped pressure

• High bottom hole temperatures � often associated with abnormal pore pressure

• Highly permeable sections � lead to differential sticking

• Reactive / swelling shales � can result in swabbing

• Faults � can act as a conduit for high pressures

Offset Pore Pressure DataThe well design will include an analysis of offset data in order to determine the porepressures to be expected. The results will be used to design both the mud programme andcasing scheme. The quality of the offset data will impact confidence in the pressureinterpretation, i.e.

• Regional observation � Overpressure encountered in adjacent fields;

• Deep seismic cut-back on shot point � good evidence if rock sequence isunderstood;

• Field observation � reasonable probability that pressures will be similar across thefield;

• Fault block observation � very high probability if the well is in the same tectonicunit;

• Adjacent well � almost a certainty.

2.3.3. Anticipated Pressure Magnitude

Zones of overpressure are seldom pressured at a single gradient, the exceptions beingpermeable carbonates sealed within massive salt sections. Commonly, in an overpressuredzone the pressure will vary sharply with depth due to localised partial depletion. In highlyoverpressured sequences, the range of individual pressures will be greatest, with occasionalhydrostatically pressured horizons possible. The resulting erratic pressure profile is difficultto interpolate between wells.

This variable pore pressure over a range of depths can cause well control problems due toalternate loss-gain scenarios resulting from an inability to maintain primary control.Anticipated pore pressure should be quantified in ranges, for example:


psi/ft kPa/m ppg

<0.47 <10.6 <9

0.47<0.62 10.6<14.1 9<12

0.62<0.73 14.1<16.5 12<14

0.73<0.83 16.5<18.8 14<16

0.83<0.94 18.8<21.2 16<18

>0.94 >21.2 >18

Figure 2.3.1 Ranges for anticipated pressure magnitude

2.3.4. H2S (in well stream)

Expected H2S levels are critical both to health, environmental and equipment selection.The anticipated concentration should be estimated, i.e.:

• 0

• 0 - 50 ppm

• 50 - 100 ppm

• 100 - 500 ppm

• 500 - 1000 ppm

• 1000 - 5000 ppm

2.3.5. Well Fluid Type

It is important that the type of fluid or gas to be encountered is known as this may affectwell control, for example:

• Connate water / native brine � No additional risk;

• Heavy oil � No significant additional risk;

• Light oil � Higher density contrast leading to migration;

• High GOR � Can be a problem if bubble point is reached during a kill;

• Dry gas � Least dense influx, highly mobile leading to migration problems;

• Condensate / retrograde fluids � can be a serious risk due to phase and thereforevolume changes which can affect bottom hole pressure;

2.3.6. Mud Type

The choice of drilling fluid can impact well control:

• Water base is generally most benign if in good condition. However, poor inhibitioncan lead to swabbing. With gas kicks, gas migration must be dealt with. In deep waterthe potential for gas hydrates must be mitigated;


• Oil based mud (OBM) generally maintains good hole conditions but gas can dissolvein the oil phase down hole and (if undetected) subsequent release at shallower depthsposes a significant risk due to rapid unconfined expansion. Numerous circulationsmay be required to de-gas after a kick;

• Synthetic oil based mud (SOBM) covers a number of proprietary products which ingeneral have the shale inhibition properties of OBM with similar risks to OBM;

• PHPA mud has excellent shale inhibition but can be prone to swabbing if a top-driveis not in use as the string has to be worked back every 30m-60m (100 to 200ft);

• Native mud usually has poor shale inhibition and poor fluid loss therefore highswabbing tendency;

• Crude oil cannot be weighted easily and can transport gas in solution masking pitgains;

• Spud mud typically has no weight above hydrostatic and can be highly prone togumbo formation and subsequent swabbing;

2.3.7. Bottom Hole Temperature

High BHTs can be a problem in terms of well control for a number reasons:

• Muds (particularly OBM and POBM) are thinned with resultant Barite drop out;

• Mud expands when static giving indications of false influxes and making thevolumetric monitoring of trips difficult;

• High temperatures are typically associated with retrograde fluids which can causeproblems maintaining primary control. These generally involve gas influxes which hitdew-point high in the hole resulting in a loss of volume. In more extreme cases, aliquid influx can pass through both the bubble point and dew point while beingcirculated to surface.

MWD/PWD tools may not operate at higher temperatures.

NOTE: Temperature should be estimated as BHT at the anticipated problem zone(and/or reservoir) rather than as a gradient

2.3.8. Fracture Margin

This is the lowest fracture gradient in the open hole (often at the shoe) minus the bottomhole pore pressure gradient.

The fracture gradient is calculated during the well design process from the interpreted porepressure, overburden and the matrix strength of the rock. The margin is essentially a safetyfactor between the fracture pressure at the weakest point in the open hole and the highestpore pressure to be encountered in that hole section.

The shoe margin at each casing point must also therefore be calculated at the design stage,i.e.:


psi/ft kPa/m ppg

0.31 7.1 6

0.21 4.7 4

0.10 2.4 2

0.05 1.2 1

<0.05 <1.2 <1

Figure 2.3.2 Typical fracture margins

2.3.9. Well Geometry

There is an industry wide move towards slim-hole well designs, driven by savings intubulars, mud, cement and rig rate. While slim wells are common place, they pose a wellcontrol hazard due to their smaller geometry, i.e. a kick will:

• Occupy a longer section of annulus per bbl;

• Exert more pressure at the shoe per bbl;

• Have a greater likelihood of unloading the hole.

The �traditional� casing scheme must be taken as a base case and any slimming down of theprofile must be evaluated as to how much additional risk is imposed. There are a limitednumber of classifications (traditional, semi-slim and slim) and the scoring used on the Riskand Level assessment must be made on professional judgement.

2.3.10. Well Profile

The two or three dimensional profile of the well can have a major impact on well control:

• Vertical well � no additional risk;

• Deviated (low angle, low radius) � no significant additional risk;

• Deviated (medium angle, medium radius) � can be problems with gas pooling on thehigh side of the hole in dog-legs etc.;

• High angle ERD � potential for continuous gas phase on the high side;

• Horizontal � possibility of very high influx volumes;

• Multi-lateral � potentially two or more different pressure regimes leading to complexkill procedures.

2.3.11. Maximum Design Pressure

The BOP must be selected to cope with the maximum anticipated surface pressure plus asafety margin. For use in the Risks and Levels Matrix (2.4), the calculated design pressuremust be used, not the actual rating of the BOP stack to be used. Due to rig availability,highly rated stacks are often used drilling very low risk wells. Use of the actual stack ratingcould unnecessarily bias the well towards a Complex status. Typical stack ratings are:

• 2kpsi - generally confined to sub-hydrostatic wells on land;


• 3kpsi - normally used for very low pressure land wells;

• 5kpsi - a 'standard' rating;

• 10kpsi - high pressure rating;

• 15kpsi and above - very high rating. (HPHT wells).

2.3.12. Rig Location

This section combines two factors into the Risk and Level matrix. The surface locationscores against ease of access and egress, supply of chemicals and support services. Thewater depth incorporates risks from choke line length, hydrates and accumulatorrequirements. The range of locations include:

• Land - Easy access;

• Land - Limited access;

• Offshore - bottom supported, inland;

• Offshore - bottom supported;

• Offshore, floating rig , <1500ft / 500m water depth;

• Offshore, floating rig, 1500ft / 500m < 6000ft / 2000m water depth;

• Offshore, floating rig, > 6000ft / 2000m water depth;

2.3.13. Remediation Risk

The pollution impact of a major well control situation is difficult to express as a numericrange due to the number of possible permutations. Each well location must be evaluatedon the specific consequences that could result and is scored according to professionaljudgement. The risk in this instance is the cost to SIEP or affiliates of remediation work,For example, criteria associated with the two end members of the series could be:

Low Risk Base Case:

• Remote desert region;

• No agriculture;

• Minimal habitation;

• Restricted surface run-off;

• Deep, concealed water table;

Typical High Risk Factors:

• Densely populated area;

• Intense agriculture;

• Shallow, exposed water table;

• Coastal or inland waterways;

• Conserved environments, e.g. rainforest, national parks, coral reefs etc.;

• High value real estate.


2.3.14. Environmental Exposure

In a similar manner to the Remediation Risk, the Environmental Exposure is difficult toexpress as a linear scale and must be presented as a base case and a series of hazards. Therisk in this case is local environmental or climatic impact on well control. These may bedirect on operations or on the supply of stock and equipment. Again, professionaljudgement must be used to determine the risk rating:

Low Risk Base Case:

• Land location;

• Good transport / communications;

• Temperate climate;

• Gentle relief;

• Politically stable.

Additional Risks May Include:

• Remote location;

• Deep water;

• Strong currents;

• Arctic conditions;

• Typhoon / hurricane prone region;

• High tidal range;

• Mountainous topography;

• Difficult transport;

• Civil unrest.

2.4. Risks and Levels in Well Control

This section demonstrates a method of determination of a relative risk value for a plannedwell. Wells with high relative risk will require a higher level of planning and control.

NOTE: This risk value or hazard quotient is only used to help highlight and raiseawareness of the possible well control risk in the well. (as some OUs do for stuck pipe risk,financial risk etc.)

2.4.1. Well Classification

For design purposes, wells are classified as Level 1,2 or Level 3 (as per SIEP EP 2000-9073, Shell Casing and Tubing design Guide). For well control issues, no similar definitiveclassification is possible because of the diversity of risks and the relative impact that eachhas on the overall plan. A continuous range exists from a low risk standard well to a veryhigh risk complex well at the other end of the spectrum.


Low Risk Standard WellComprises 'traditional' well designs with low risk ratings typified by:

− Well known area;

− High fracture margins;

− Few potential hazards;

− Easy access and escape.

High Risk Complex WellThis well type encompasses a greater degree of risk imposed by either well conditions,profile or location. Typical examples will include:

− Unknown area;

− Deepwater locations;

− Low fracture margins;

− Tortuous and/or long well designs

− High formation pressures;

− Shallow gas prone areas;

− Known hazards eg. H2S, High Temperature etc.

2.4.2. Assessment Process

The following pages illustrate a system of evaluation by assigning a score for a number ofhazards defined by the well design. Individual risk scores are determined from the HazardRating Matrix.

Regardless of the indicated relative risk, under no circumstances should design orexecution of well control operations be less than the minimum standards recommendedthroughout this manual.


2.4.3. Hazard Rating MatrixNo. HAZARD 1 2 3 4 5 6 7 8 9 101 Shallow

Gas RiskNo Evidence Regional

PhenomenaLocalPhenomena

Oil Seeps ShallowSeismicAnomaly

Seabed PockMarks

Observed GasSeep

2 OverPressureRisk

No Evidence Seismic Cut-Back on ShotPoint

Field WideObserved

Fault BlockObserved

Adjacent Well

3 AnticipatedPressure Risk

<0.47psi/ft<10.6kPa/m<9ppg

0.47<0.62psi/ft10.6<14.1kPa/m9<12ppg

0.62<0.73psi/ft14.1<16.5kPa/m12<14ppg

0.73<0.83psi/ft16.5<18.8kPa/m14<16ppg

0.83<0.94psi/ft18.8<21.2kPa/m16<18ppg

>0.94psi/ft>21.2kPa/m>18ppg

4 H2S % Zero 0-50ppm <500ppm <1000ppm >1000ppm5 Well Fluid Type Water / Brine Heavy Oil Light Oil High GOR Dry Gas Condensate /

RetrogradeFluids

6 Mud Type WBM Pseudo Oil IOEM PHPA Native Mud Lease Crude Spud Mud

7 Bottom HoleTemperature

<40°C<100°F

40<65°C100<150°F

65<95°C150<200°F

95<120°C200<250°F

>150°C>300°F

8 Shoe Margin >0.31psi/ft>7.1kPa/m>6ppg

0.31>0.21psi/ft7.1>4.7kPa/m6>4ppg

0.21>0.10psi/ft4.7>2.4kPa/m4>2ppg

0.1>0.05psi/ft2.4>1.2kPa/m2>1ppg

<0.05psi/ft<1.2kPa/m<1ppg

9 Well Geometry Traditional Semi-Slim Slim-Hole10 Well Profile Vertical Low angle

Low radiusMed angleMed radius

ERD Horizontal Multi- Lateral

11 MaximumDesign Pressure

2k 5k 10k 15k >15k

12 Rig Location LandEasy Access

Land LimitedAccess

Inland BottomSupported

OffshoreBottomSupported

Floater<500mWater Depth

Floater500<2000mWater Depth

Floater>2000mWater Depth

13 RemediationRisk

LowRiskBase Case

LowLevel Impact

Medium LevelImpact

HighLevel Impact

Exxon ValdezScale

14 EnvironmentalExposure

LowRiskBase Case

MinimalAdversity

SignificantAdversity

SeriousConditions

ExtremeConditions


2.4.4. Hazard Quotient Evaluation Table

No. HAZARD Score

1 Shallow Gas

2 Overpressure

3 Anticipated Pressure Magnitude

4 H2S

5 Well Fluid Type

6 Mud Type

7 Bottom Hole Temperature

8 Shoe Margin

9 Well Geometry

10 Well Profile

11 Maximum Design Pressure

12 Rig Location

13 Remediation Risk

14 Environmental Exposure

NOTE: The purpose in assessing a hazard quotient is to evaluate potential areas ofconcern during the well design process. The results can be used to compare wells orsections of a well. The objective is to raise awareness of the level of well control risk, andto identify factors which may:• Increase the probability of a kick on a particular well• Add complexity to any subsequent well control operationsOnce identified, risk from high scored hazards should be mitigated by changes to the welldesign or by the application of specific procedures / controls.


2.5. Example of Concurrent Operations Policy

Shell Expro NBU Concurrent Operations Document (Extract)

Operation RiskLevel

Drilling or workover with conventional rig (No risk of hydrocarbons) 0Drilling or workover with conventional rig (Risk of hydrocarbons) 2

Drilling or Workover with HWU, CTU or Hybrid (No risk of hydrocarbons) 0Drilling or Workover with HWU, CTU or Hybrid (Risk of hydrocarbons) 2

Wireline intervention through Tree (Actuated UMGV with ability to cut wire) 1Wireline intervention through Tree (Actuated UMGV compromised) 2

Other Non-subsurface Operations, Requiring Category 2 Hot Work Permits(except Open Electrics) in associated areas, opening hydrocarbon systems.

1

Other Non-subsurface Operations, Category 1 Hot Work/HeavyLifting/Opening Electrics in associated areas or opening a hydrocarbon systemwith one of the barriers jeopardised

3

The combined risk must not exceed 3 for concurrent operations to take place withoutspecific review.

The risk level does not take into consideration an escalation factor such as adverse weatherconditions or if one or more safety systems fail or are temporarily disabled etc. Because ofthe complexity, the precise limitations on working conditions must be established on site.

Conducting operations with a combined risk level greater than 3 is permitted when it canbe demonstrated that appropriate measures are in place to manage any situation that mayincrease risks significantly above those envisaged, is likely to occur.

The key to successful concurrent operations with minimum increase in risk is to identifythe potential problems/clashes and develop a means of managing these to minimise therisk. This may involve delaying one operation until a high risk or critical activity (such ascementing) is completed on the other operation.

It is also vital that when a problem does occur there is an agreed method to ensure thatother activities are managed appropriately to reduce the potential for escalation shouldcomplications arise.


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