section c1 fluids management - cabot specialty fluids

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Section C1Fluids Management

NOTICE AND DISCLAIMER. The data and conclusions contained herein are based on work believed to be reliable; however, CABOT cannot and does not guarantee that similar results and/or conclusions will be obtained by others. This information is provided as a convenience and for infor-mational purposes only. No guarantee or warranty as to this information, or any product to which it relates, is given or implied. CABOT DISCLAIMS ALL WARRANTIES EXPRESS OR IMPLIED, INCLUDING MERCHANTABILITY OR FITNESS FOR A PARTICULAR PURPOSE AS TO (i) SUCH INFOR-MATION, (ii) ANY PRODUCT OR (iii) INTELLECTUAL PROPERTY INFRINGEMENT. In no event is CABOT responsible for, and CABOT does not accept and hereby disclaims liability for, any damages whatsoever in connection with the use of or reliance on this information or any product to which it relates.

© 2008 Cabot Corporation, M.A.-U.S.A. All rights reserved. CABOT is a registered trademark of Cabot Corporation.

C1.1 Introduction ........................................................................................... 2 C1.2 Methodology ........................................................................................ 2

C1.3 Formate brine supply, utilization and recovery process ..................... 2 C1.3.1 Planning and preparation .................................................................. 3 C1.3.2 Supply ............................................................................................... 4 C1.3.3 Rig storage and surface handling .................................................... 6 C1.3.4 Well bore operations ........................................................................ 8 C1.3.5 Sub-surface ..................................................................................... 12 C1.3.6 Brine recovery and return ............................................................... 15 C1.3.7 Brine reclamation ............................................................................ 16

C1.4 Summary – the life cycle of a formate brine fluid ............................... 19

C1.5 Fluid sampling ...................................................................................... 19

References .................................................................................................... 20

Appendix 1 Rig fluids management checklist .............................................. 21

Appendix 2 Cabot rig audit questionnaire ................................................... 25

The Formate Technical Manual is continually updated. To check if a newer version of this section exists please visit www.formatebrines.com/manual

FORMATE FIELD PROCEDURES AND APPLICATIONS

F O R M A T E T E C H N I C A L M A N U A LC A B O T S P E C I A L T Y F L U I D S

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C A B O T S P E C I A L T Y F L U I D S

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F O R M A T E T E C H N I C A L M A N U A L

S E C T I O N C 1

C1.1 Introduction

Effective fluids management is essential in well construction operations in order to reduce:

• Costs• Wellcontrolincidents• Environmentalimpact• Formationdamage• Formationevaluationproblems

It is particularly important to reduce losses and contamination of high-value drilling and completion fluids. Cesium formate brine, being both high-value and in limited supply, requires very careful husbandry at all times. Gross contamination of cesium formate brine with other aqueous fluids may significantly reduce its value.

In order to minimize fluid losses it is essential to first map out where the losses typically take place in a well construction project and then understand why and how the losses occur. Such an exercise was undertaken by Cabot Specialty Fluids (CSF) in the 1990’s, prior to the first field use of cesium formate brine.

Losses of high-density zinc bromide brine during completion jobs in the North Sea were analyzed to establish the typical fluid loss routes and patterns [1]. The results of this study were used to devise procedures to minimize losses of cesium formate brine in completion operations. The findings from this original study have been modified and improved over time as experience has been gained in running completion fluids based on cesium formate brine. Implementation of these upgraded procedures has resulted in significant reductions in losses of cesium formate [2].

The objectives of this document are to:

• Analyzethecycleofsupply,application,andreturn of high-density formate brines in offshore well construction projects

• Identifythepointsatwhichthereispotentialforbrine losses and contamination to occur

• Quantifytherisksintermsofprobabilityandimpact• Detailtechniquestoeliminateorreducetherisk

of losses and contamination • Definekeyresponsibilitiesandaccountabilitiesin

brine loss management

C1.2 Methodology

In order to improve on existing loss reduction practices that have been developed for the transport and use of traditional heavy brines and oil-based

muds, it is necessary to go back to basics and conduct a detailed analysis of the fluid supply cycle, application and return (including re-conditioning) in offshore drilling and completion operations. This is achieved by analyzing the various stages in the brine utilization cycle. The analysis facilitates the subsequent use of risk analysis techniques to identify key areas for attention, while additionally focusing on ownership issues attached to the management methods adopted for loss reduction. In addition to this type of theoretical approach, a study of six well completion operations where traditional bromide-based heavy brines have been used has served to focus attention on key areas where brine has been lost in the past. The study sorted or classified brine losses into the following five categories:

• Transit – losses incurred between onshore brine plant and the rig and vice versa

• Surface handling – losses on the rig but not directly related to, or as a consequence of, well bore operations

• Well bore operations – losses directly related to, or as a consequence of, operations conducted with the brine in the well bore

• Subsurface – brine lost to the formation or left in the well bore below packers or plugs

• Other – losses that cannot be accurately attributed to any of the above categories and are dealt with in the analysis on a case-by-case basis

This document utilizes the same loss categorization system, with the exception that outward and return ‘transit’ operations are dealt with separately. Also, the process of reclamation, which was previously considered part of the return transit, is now treated separately.

Although this document is tailored to offshore facilities, similar methodology applies to land rigs and the different transportation procedures applied in these operations.

C1.3 Formate brine supply, utilization, and recovery process

The process of brine supply, utilization, and recovery for an offshore completion operation can be segmented into seven main phases to facilitate identification, assessment, and management of brine loss risk. Although these phases are broadly sequen-tial, there can be considerable overlap, with activities in two or more categories occurring simultaneously.


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S E C T I O N C : F O R M A T E F I E L D P R O C E D U R E S A N D A P P L I C A T I O N S


Note: Simultaneous operations with brine (such as displacing out of the well and loading to the boat at the same time)

increase the risk of creating brine losses and should be avoided whenever possible.

1. Planning and preparation, including audit of the rig’s brine handling and storage facilities and procedures, and assignment of responsibilities and accountabilities.

2. Supply of brine from CSF’s storage, either directly to a supply vessel or via a mud / brine contractor’s plant to the supply vessel – to storage on the rig. This covers all the steps in the shore to ship and ship to rig process, including final preparation of the rig for receipt and storage, the physical integrity of the rig’s bulk liquid systems and, finally, housekeeping aspects of brine storage and handling.

3. Rig storage and surface handling, including all operations with, or movements of, brine that are not directly related to actual well bore operations. This covers storage, surface movements and uses of the brine, sources of contamination, and volume and condition monitoring.

4. Utilization of the brine in well bore operations, including intra-rig movements, displacements in and out of the hole, treatment of interfaces, use of specialized pills or additives, dilution and weighting-up procedures, volume, and condition monitoring.

5. Subsurface losses, including contingency planning for sub-surface losses to the formation and consideration of fluid left below packers or lost when flowing the well.

6. Recovery and return of brine to CSF’s storage tanks, including back-load procedures, recovery from the supply vessel, volume and condition monitoring, chemical analysis, mechanical, and chemical reclamation procedures.

7. Reclamation, including chemical analysis, mechanical and chemical reclamation processes, surveying, and finally waste disposal.

C1.3.1 Planning and preparation

The planning and preparation stage consists of the following steps:

Rig auditAn essential precursor to the supply of high-density brine to any installation is a thorough inspection of the rig’s fluid handling and storage systems and procedures. An experienced fluid loss control engineer, assisted by the rig site mud / completion fluid engineer and appropriate rig personnel – the system ‘owners’ and ‘managers’ should perform this survey together. The rig’s barge engineer or equivalent will

be a key resource in performing this task.The purpose of the survey is to identify areas of potential loss and cross-contamination throughout the fluid system and to recommend changes to rectify any shortcomings, either in physical plant or equipment, or in fluid management procedures. The layout, location, and operating procedures of all fluid handling and storage systems must be rigorously reviewed, including:

• Supplyvesselordeliveryvehicle–rigtransfersystems and procedures

• Storage,mixing,andinternalrigtransfersystemsand procedures

• Integrityofallvalves–suctiontankandtransferlines, equalizing and dump valves, etc.

• Availabilityofsufficienttanksforstorage/isolationof pills, interfaces, and contaminated fluids

• Suitabilityandlocationofrelevantfluidprocessing equipment, such as portable liquid recovery units

• PotentialtouseMPTs(MarinePortableTanks)orother deck storage tanks to increase capacity and / or operational flexibility

• Thetypeandconditionofallvalves,sensors,flow-line meters, and volume meters or measure ment systems

• Establishmentoftotalcontainmentforformate-based fluids

• Exclusionofcontaminantsfromthesystem,including rain water

The report from the survey should identify a suitable configuration of tanks and lines for displacement of the well to brine, including tank designation for returns, clean brine, clean-up and displacement pills, and contaminated interfaces.

Note: It is recommended that wherever possible pits containing high-density

formate brines and pits containing other fluids should be separated from each

other by at least two valves.

A diagrammatic representation of the surface system is recommended (preferably electronic), to monitor all transfers, contents, and tank and line configurations. This should be prominently displayed and continually updated. The possibility of using a separate and dedicated system for brine intra-rig transfer should be investigated. Such a system could consist, for example, of a portable, skid-mounted pump along with kink-resistant flexible lines. This would eliminate the use of the larger bore (and possibly contaminated) rig lines for surface fluid transfers and processing. In addition, it would be much


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easier to drain down such a system, thus reducing the potential loss of fluid on surface. If not already in place, consideration should be given to colour coding hose lines and valves. The location and controls on the use of water lines in the mud room and drill floor should be reviewed, as this is a significant potential source of contamination of dense brines. Closed storage tanks should be used if practicable.

A blank audit form is attached in Appendix 1.

Responsibilities and accountabilitiesResponsibilities and accountabilities should be clearly delineated and unambiguous lines of communication and control established. Although the precise allocation of responsibilities may vary from rig to rig, it is recommended that the roles of the relevant personnel, the accountability relation ships, and those who should be consulted or informed be defined at this stage. The roles are defined as follows: • Responsible – the person or group actually

carrying out the task or activity• Accountable – the person accountable for

ensuring that the task or activity is carried out, including communicating requirements and instructions, and ensuring the appropriate resources are available

• Consult – person(s) to be consulted prior to key activities, particularly if any deviation from the agreed plan is being considered, or if a decision point in the process is reached

• Inform – person(s) to be informed of activities, events, decisions, and outcomes

The agenda for pre-operations meetings should be addressed along with clear guidelines on which personnel should attend, to ensure that all participants are clearly informed of their roles and those of others.

C1.3.2 Supply

Preparation of required volume and densityBrine ownership and the associated risk of losses rest with CSF until the correct volume of mixed or component brines is delivered to the end user or his designated agent, which may be the supply vessel, the mud / brine company or a designated mixing facility. Mitigation of this risk is through clear, written agreement on volume and density of mixed orcomponentbrinestobedelivered,theQA/QCprocedures of CSF or CSF’s agent, and the use of independent agents for chemical analysis, density, and volume measurement. Three techniques are available for measurement of bulk volumes delivered by CSF:

1. Tank volume gauges.2. A permanently installed flowmeter.3. Delivered net weight determined by road tanker

weigh-bridge measurements or pallet scales.

Experience has shown that the last method is the most accurate. Brine volumes vary with temperature, but if a known weight is delivered, the volume at the standard reference temperature for brine density measurement (15.6°C / 60°F) can then be accurately calculated. Whichever method or combination of methods is used, delivered volume and specifications must be fully documented.

Delivery to end-user’s appointed agentWhen delivery is completed the cost of loss moves to the end user, as does ultimate ownership of the risk(s) of losses. The management of risk may be shared with the agent and the end user, or fully devolved to the agent with the end user retaining an audit function.

Delivery to mud / brine contractor All tanks, valves, lines, and hoses should be certified as fit for purpose and clean as per the contractorsQA/QCprocedures.Tanksmustbeproperly calibrated and equipped with very accurate means of volume measurement. It is strongly recommended that dedicated formate brine tanks with separate lines are used for onshore storage and processing. Only closed tanks should be used for storage, and any further blending, additions or other treatments must be agreed with CSF and communicated in writing. Volumes and density will be re-checked by an independent agent after any such processing is carried out and the results documented. On sampling, simultaneous top and bottom samples are recommended. Every effort must be made to recover fluid from mixing tanks and transfer lines. Ideally, flexible lines should be fitted with closeable valves to allow hose contents to be recovered prior to disconnection. Fluid loss risk, while in the mud / brine contractor’s plant, rests with the designated plant operator, while management responsibility lies with the supervising engineer or coordinator accountable to the end user.

Delivery to the supply vesselThis may be via a mud / brine contractor’s plant or directly by CSF or CSF’s appointed agent. Given the value of cesium-based brines, the use of a dedicated vessel is justifiable. A key way to reduce transit losses is to minimize the number of movements – the review of brine


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losses on previous wells [2] showed that losses were higher when delivery was split between numerous small shipments, as opposed to one or two large movements. This should be considered in ship selection and logistics planning. In any event, the supply boat used must be equipped with a pump, which is able to lift fluids of high density up to the rig. When the boat arrives all hatches into the brine tanks should be opened. The tank(s) should be visually inspected for cleanliness and absence of excess moisture. The loading lines, pumps, and delivery manifolds should also be inspected and certified clear. If lines, tanks, manifolds, etc. do not pass these inspections, the vessel captain and the end user’s representative should be immediately notified. Calibration of the supply vessel’s tanks should be verified in order to accurately cross-reference volume delivered against volume received on the ship. Assuming no problems are found on the inspection, the plant operator goes over the loading sequence with the vessel’s engineer to ensure that all valves are correctly aligned and that no intermingling or loss of fluid will occur. After loading, the vessel’s engineer ensures (as risk ‘owner’) that the tanks holding fluid are sealed and isolated. Also, the CSF or brine company representative ensures that the vessel engineer understands the nature and value of the cargo, and hence the importance of avoiding any losses or contamination. As cesium and potassium formate are essentially non-corrosive there is no need for lined tanks. Finally, no other type of fluid should be back loaded into the tanks used for delivery, as vacuum tankers are used to recover residual fluid on return to port. Risk ownership after loading and until the fluid is received on the rig lies with the supply vessel engineer and deck crew, and early involvement and briefing are important to secure their fullest co-operation.

Risk management to the point the fluid is delivered to the rig rests with the CSF representative or the mud / brine contractor representative. The agreed volume and density delivered (as soon as the latter is checked from the samples taken during loading), must be promptly communicated to the rig to ensure appropriate tanks are available to receive it. In early operations with cesium formate brine, losses from shipping offshore by supply vessel averaged some 3.7% of brine shipped out and 6.1% of brine shipped back. The key levers for reducing this further are summarized as follows: • Dedicatedboatwithenhancedrecoveryoptions• Minimalnumberofmovements• Planningandpreparation

More recent experience with cesium formate brine transfers, where these more rigorous controls and procedures were used, has resulted in much lower levels of shipping losses as detailed in Table 1. Delivery by ISO / IBC Although this document focuses on offshore operations, most of its content is relevant for land-based installations. However, land rigs obviously involve different brine transportation procedures using ISO tanks or IBCs. The two common ISO tanks are 20 and 30ft long with 27 m3 / 170 bbl and 32.5 m3 / 205 bbl fluid capacity respectively. The amount of brine carried in each ISO tank is determined by local regulations (axle load and stability regulations). IBCs are designed to hold around 1 m3 / 6.3 bbls fluid, although the volume is reduced to around 0.85 m3 / 5 bbls to stay within the IBC rating when carrying high- density brines. The number of IBCs carried by each truck is once again determined by truck and road axle load limitations, and may be reduced further depending on the quality of roads and tracks leading to the rig site. Whichever transportation container is used, brine is transferred to the rig tanks using a (diaphragm) transfer pump and hoses.

Table 1 Recent levels of shipping losses.

Well # Density Volume (m3)

Transit loss out Transit loss in Total transit loss[m3] [bbl] [%] [m3] [bbl] [%] [m3] [bbl] [%]

1 2.20 30.40

2 2.19 250.49 0.55 3.5 0.20 0.55 3.5 0.20

3 2.19 188.83

4 2.19 258.19 0.71 4.5 0.27 3.49* 22.0 1.35 4.20 26.4 1.63

5 2.19 288.42 -1.1 -6.9 -0.38 1.69 10.6 0.58 0.59 3.7 0.20

Average 2.19 0.16 1.00 0.03 1.04 5.6 0.39 1.07 6.7 0.40

* Mainly due to solids drop out on the boat


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Final preparation of the rig to receive the brineOnce the cesium / potassium formate brine has arrived on the rig ‘risk ownership’ rests with the fluid engineer, with his onshore supervisor having management responsibility. The exact brine volume, along with density, are communicated to him shortly after loading. Prior to its arrival he is responsible for ensuring that the rig systems are prepared and fit for purpose. The receiving tanks must be clean and dry, transfer hose clean (a dedicated hose is recommended), and manifolds, connections, and non-return valve (if fitted) checked and appropriately aligned. If mud pits are used for brine storage or handling they should be cleaned to ‘clean brine standard’ and pressure-washed from the top down paying particular attention to grating, beams, corners, and crevices where mud residues may lodge. When all pits are clean the final rinse water should be used to test all valves and gates for leakage by pumping against them when in the closed position. All tank lines should be drained down before the pits are cleaned and dried. Tanks and pits should be made as dry as is practicable using squeegees and mops, and lines cracked open at flanges and blown through with rig air or drained down using a Wilden pump. All dump and equalizer valves should be sealed with silicone sealant to eliminate leaks. Pump packings should be checked for leaks and repacked where necessary, since the cost of new packings is negligible compared to the cost of lost brine. The packings on mixing and transfer pumps should be inspected and adjusted whilst flushing out the system with water. New packings should be only finger tightened at first and the leakage adjusted over two hours at not more than one-quarter turn per adjustment. Replacing packings with brine in the system invariably results in some wastage of brine when draining lines. There is also a tendency to over tighten, which can result in early damage and reduced packing life. Finally, prior to taking on formate brines all water lines around the pits should be sealed off or disconnected to prevent accidental water contamination and dilution incidents.

Off-loading the brine from the supply vesselA pre-job meeting should be held to ensure that all parties involved in the operation are familiar with the correct procedures and lines of communication and control. The supply vessel engineer should participate via a telephone hook-up if possible. In any event, the pumping sequence should be clearly agreed with him, and clear lines of communication

and monitoring systems established before off-loading begins.

Once off-loading is complete the fluid engineer should accurately measure the volumes received and record the density. If there is any serious discrepancy the end user representative, vessel engineer, and captain are immediately informed and plans made to recover the remaining volume upon return to port. If sea conditions and deck loading permit, the vessel engineer should visually inspect the vessel tanks for remaining fluid volumes before the vessel departs the rig.

UtilizationFluid risk loss management during completion or testing operations is, of course, influenced by the precise nature of the operations and, in particular, by well conditions and completion design. Therefore, detailed risk assessment and implementation of a loss management plan is dependent on close study of the completion or well testing program. Nonetheless, the main risks can be categorized and loss management principles outlined. ‘Ownership’ and ‘management’ again rest with the fluid engineer and his supervisor respectively.

C1.3.3 Rig storage and surface handling

Historically, the largest brine losses occur during rig storage and handling [2]. However, it is also the area where good management and detailed planning can make the biggest impact in reducing losses, since it involves activities carried out visibly on surface. As a reminder, these losses are defined as “occurring on the rig, but not directly related to, or as a consequence of, well bore operations”. These losses will be addressed under the following sub-categories:

• Pits,tanks,andtransfers• Linesandpressuretesting• Leaksandshakers• Filtration• Volumesandconditionmonitoring

Pits, tanks, and transfersAll handling and transfers of brine in the surface active, reserve, and storage tanks presents a potential for losses. Similar to shipping loss reduction, fewer movements mean lower losses. An accumulation of small losses occurring during routine brine-handling operations on the rig can quickly result in significant financial costs. Job planning must aim to reduce to the workable minimum the movements of brine from or between storage tanks, reserve pits, active pits, and


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treatment areas, and equipment such as filtration units. Each time fluid is moved there is a potential for losses in lines, pumps, and in dead volume. Brine should not be placed in containers, such as pontoon tanks where recovery of residual volumes may be very difficult. The point during the pre-completion operations (well clean up, etc.) when the brine is taken on board should be carefully considered, not only to minimize contamination risks, but also to eliminate any need to transfer brine between tanks. Ideally, the only transfers that should be made are into or out of the well. Pits or tanks designated for brine storage should be those which facilitate displacement into or out of the well without the need for intermediate transfers. Normally these will be the active pits. Leg or pontoon tanks should not be used unless absolutely necessary and only then if full recovery of the brine is possible, either by the primary piping or by access using secondary recovery equipment. Any inter-tank transfers should avoid the use of the rig’s piping system, if feasible, and rely instead on a dedicated set of hoses or chiksans linked to a skid-mounted pump unit. As losses are primarily from un-pumpable (‘dead’) volumes in pits and tanks, or brine left in lines or hoses, it follows that most of these losses can be eliminated by avoiding these activities, i.e. avoid transfering brine around the rig, and bypass the rig’s piping whenever possible by using drainable hoses. The main exception to the latter is, of course, displacing into the hole when it is not feasible to bypass the rig system. The pits used should be those that offer the shortest lines to the drill floor; again these will normally be the active pits. Appropriate fluid recovery equipment should be available for use on the rig floor, in the pits and at all fluid treatment areas to recover dead volume and spills. Thorough use of secondary recovery equipment to recover ‘dead’ volume, together with MPTs to contain the recovered brine, further reduces losses from this source.

Adding brine liquor from IBCsWhilst cesium formate brine is not hazardous to work with, traditional methods of decanting brine from IBCs carry safety risks due to the weight of the IBCs and a risk of splashing and spillage. A Venturi suction line or diaphragm pump should be used to empty IBCs into the mixing system. The safest and most efficient way to add brine liquor from IBCs is by suction via the bulk chemical hopper Venturi or a similar dedicated unit from the

cesium brine specific transfer and mixing set-up. Suction should be via a chemical, collapse, and kink-resistant hose fitted with a non-return valve.

Overboard dischargesAlthough environmentally acceptable, overboard discharges of cesium / potassium formate are economically unacceptable. Even fluids where cesium / potassium formate forms a minor fraction, such as interface fluids, may nonetheless be worth recovering for reclamation. To prevent accidental discharge, the drilling unit should be set up for zero fluid discharge, with all overboard lines from the pits, rig floor, and fluid treatment areas sealed or diverted to holding tanks. This should be completed after the well and surface system is cleaned up, prior to the well being displaced to cesium / potassium formate brine, and continue until the well is completed and the cesium / potassium formate brine has been back loaded. The contents of the holding tanks may then be pumped into MPTs and sent to town for evaluation and reclamation where economic.

Lines and pressure testingThese types of losses also occur primarily on surface and, in the past, consisted of brine lost in lines when transferred or pumped up to other pressure testing equipment, cement units, BOPs, or well testing equipment. In general, similar recommendations can be made to reduce losses during other surface-handling operations. Where possible avoid using fixed piping and use flexible hoses or chiksans to deliver brine to where it is required, so that it may be subsequently recovered. If surface equipment must be pressure tested and this cannot be done with water, then it should be a task-planning priority to consider how this might be done without risk of losing the brine used to fill up the lines or equipment being tested. It is best to avoid alternating between water and brine as a pressure testing medium as this results in constant small dilutions with water. If BOP maintenance or repairs are required with cesium / potassium formate fluid in the well, an air diaphragm pump should be used to evacuate the fluid. Ball valves should be installed on both ends of the hoses to prevent spillage during disconnection.

Leaks and shakersIn the sample of wells reviewed with other fluids, significant losses were reported from riser slip joints, flow line gates, dump valves, pump packings, burst hoses, etc. Common to all these loses is that they are largely avoidable with effective preventative maintenance and other pre-emptive measures. As detailed in the section on final preparation of the


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rig, pre-emptive renewal of pump packings, seals, and hoses, along with thorough checking of pipes, lines and risers can virtually eliminate this type of loss.

All normal circulation, for example to condition or homogenise brine density, should be done under conditions of total containment, with the shakers bypassed and the gates sealed. Losses at the shakers are most likely to occur if it is necessary to mill with the brine. However, under zero discharge conditions these loses should be limited to the small volume that cannot be recovered mechanically from the milled swarf.

FiltrationThe need for offshore filtration is generally a result of contamination from either a badly cleaned well bore or inadequately prepared rig fluids system. Provided these operations are properly conducted even extensive circulating with brine should not result in serious contamination. If offshore filtration is required, the use of a cartridge unit is the preferred option for lightly contaminated fluid as this results in lower losses in the filtration media and in lines and plumbing. However, for more serious contamination, filter press equipment may be necessary and appropriate measures should be taken to recover fluid in the lines. Filtration and reclamation is dealt with in more detail in the section on brine recovery.

Volume and condition monitoringResponsibility for safeguarding the brine rests with the drill crew as well as the brine and loss engineers. One member of each crew should be designated to work with the fluid engineers in any operation involving the brine on surface. This individual should be thoroughly familiar with the rig fluid storage and handling systems. Brine volumes in the tanks should be checked hourly and recorded; and brine volume, density, and pH should be recorded at each changeover to emphasize accountability. The key levers in reducing losses due to surface handling can be summarized as follows:

• Establishzerodischargeconditions• Usedesignated,isolatedtanks• Minimizethenumberofbrinemovementsonsurface• Avoidtheuseofrigpiping• Painstakinguseofsecondaryrecoveryequipment

C1.3.4 Well bore operations

These are defined as losses directly related to, or as a consequence of, operations conducted with the brine in the well bore. Loss management for this type of loss will be considered under three sub-headings:

• Displacementsandinterfaces• Tripping• Sub-surfacelosses

Displacements and interfacesIt should be noted that most losses attributed to displacements and interfaces are actually discarded rather than lost. Generally, co-mingling different well bore fluids results in the fluids being discarded, either because they are fundamentally incompatible, or because reclamation of the theoretically valuable constituents is not considered technically or commercially viable. As always, the key to reducing this type of loss lies in risk avoidance.

Note: Cesium / potassium formate brine should not be exposed to the risk of contamination by fundamentally

incompatible fluids, such as concentrated halide brines or drilling muds – particularly

oil-based muds.

For cased and non-perforated completions, an intermediate displacement to seawater (provided casing pressure limitations permit), is preferred to reduce the likelihood of badly contaminated interfaces from which cesium / potassium formate brine cannot be recovered. Indirect displacement is more likely to produce good results in the well clean-up, thereby reducing the need for lengthy filtration of the completion fluid, which will inevitably involve some fluid loss. It is, however, recognized that in other completion designs, e.g. perforated or where the reservoir is not isolated by a mechanical barrier, direct displacement may be required for reasons of pressure control and / or to minimize circulation time and the possibility of formation damage.

Note: Whilst displacing cesium brines into or out of the well, spacers should be

based on cheaper but still compatible fluids.

In the case of cesium or blended cesium / potassium formate brines, this should be potassium or sodium formate. In cases where cesium / potassium formate is displaced out of the hole these fluids, in addition to being compatible, have the advantage of having a lower density than the completion fluid and more than than that of the most likely long-term packer fluid (water). In some cases where cesium / potassium formate is being used as a completion fluid, the operation that precedes displacement of the formate brine


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into the hole is a well clean up, mainly conducted with seawater. In other cases where direct displacement from or to drilling fluid is necessary, the use of potassium formate-based spacers are also advised where appropriate. If a well is being directly displaced from oil-based mud to cesium / potassium formate brine, an intermediate displacement and partial clean up using sacrificial water-based mud and the appropriate clean-up chemicals has been found to be highly effective [3].

Interface lossesThere are two critical aspects to avoiding the loss of interface fluid during displacements: the design of spacers used to prevent inter-mingling, and the displacement procedures and techniques.

Spacer designThe four key parameters in spacer design are:

• Density – optimum density is midway between the densities of the two fluids to be separated

• Viscosity – if the two fluids to be separated are of low viscosity, a high viscosity spacer may enhance separation, but consideration would then need to be given to potential filtration problems involving the removal of viscosifying polymers

• Volume – separation of at least 1,000 feet is recommended, requiring a minimum of 50 bbl for a 9½" x 5" annulus for example

• Detection – the end of the spacer is detectable due to different density and viscosity

Note: For displacement to or from high-density cesium / potassium formate

brine, whenever possible always use unviscosified potassium formate brine as

the last spacer when displacing the formate brine into the well and as the first

spacer when displacing the formate brine out of the well. Contamination of the brine with viscosified fluids complicates

reclamation.

If a density requirement (> 1.57 s.g. / 13.1 ppg) applies to the spacer, so that an unweighted potassium formate brine cannot be used, a solid weighting material and viscosifier must be added (illmenite is often used).

Displacement techniquesThe main factors that need to be addressed in respect of displacement procedures are as follows:

• Direct or indirect displacements – as discussed above, this is essentially a consequence of completion type with direct displacements normally only necessary when there is communication with the reservoir, or where casing strength limitations dictate

• Displacement direction – the choice of conventional or reverse circulation is best made on the basis of the relative densities of the displacing and displaced fluid. Where seawater is being displaced out by heavy brine, conventional circulation is recommended if the string capacity is smaller than the annulus volume because fluid channelling only occurs as the heavier brine pushes the seawater down the string. When displacing heavy brine with seawater, reverse circulation is recommended if the string capacity is smaller than the annulus volume because fluid channelling only occurs while seawater is pushing the heavier brine up the string. In this way, the lighter fluid is always kept above the heavier fluid in the larger volume annulus. This helps to reduce any mixing or channelling in the annulus, especially if pumping is stopped for any reason during displacement

• Flow regimes – laminar or turbulent? This choice is more critical in direct displacements where the well clean up is part of the displacement procedure. Generally, turbulent flow improves the scouring or cleaning action of surfactant pills, which may be pumped ahead of the brine. Turbulent flow also tends to promote a flatter profile of fluid flow and can reduce channelling, particularly in high angle or horizontal sections. For this reason, even with indirect displacement where the well has been cleaned up and

displaced to sea water prior to displacement to brine, it is recommended to displace with the fastest available pump rate for 90% of the calculated displacement strokes for theoretical arrival of the spacer on surface, unless indications of the spacer are seen earlier

• Pipe movement – rotation and reciprocation. Although more critical in direct displacements, these actions can assist well bore cleaning. Here, rotation at 50 rpm is advised to displace seawater with heavy brine, as it reduces channelling, especially in deviated wells

Although the displacement rate should be maximized, when conventional or reverse circulation is selected to minimize channelling, this is not always possible when recovering high-density formate brine from the hole after running completion tubing that incorporates a down-hole packer. The displace ment rate may be restricted in order to prevent any risk of washing out the packer seals, and the displacement direction may be governed by the need to avoid accidentally setting the packer prematurely during the displacement.


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S E C T I O N C 1

Displacement loss managementAs the process of displacement has been clearly identified as a major source of losses in past operations with heavy brines, improved management of it is of critical importance. First, a documented plan must be prepared, based on consideration of the following factors:1. Well geometry and volumes.2. Fluid in place and fluid to be introduced.3. The influence of temperature and pressure.4. Pressure control (where relevant) and circulating

pressures.5. Physical limitation of rig or tubulars.6. Displacement method – direct or indirect,

conventional or reverse.7. Spacer design – density, viscosity, volume, and

detection.8. Pit and flow line control.9. Monitoring, management, documentation, and

evaluation.

Mud conditioningWhere mud is displaced out of the hole it is important to condition the mud to facilitate a clean displacement. In high-solids muds it is especially critical to do as much as possible to reduce barite sag prior to direct displacements, as this can result in severe solids contamination of the brine.

Isolation and treatment of interfacesAll interfaces should be isolated and tested according to pre-agreed protocols. The fluid engineer has the capability to conduct pilot tests to establish if the fluid can be re-conditioned on the rig via filtration, density adjustment, pH adjustment, or other chemical means. If this is considered impractical, the fluid should either be back loaded (using MPT’s if possible), or a sample should be sent to town for more detailed analysis prior to determination of the fluid’s final disposition. Due to its value, no fluid containing cesium formate should be dumped unless operationally unavoidable. Where possible, written authority should be obtained from town first, and quantity and analysis results fully documented.

Contaminants, pills, and sweepsIn respect of dense brines there are a variety of contaminants that can result in either costly losses or expensive treatments to restore specifications. The list includes water, drilling fluid, hydrocarbons, particulate matter, rust, polymers, LCM material, pipe and tubing dope, dissolved scale, etc. Some contamination is intentional, e.g. when the brine is used as a carrier for other materials, such as LCM, or where it is used to make various sweeps or spacers. As with interfaces, any contaminated fluids returned to surface, should be diverted for testing

and reclamation. Only the use of additives where effective and economical reclamation techniques have been established, tested, and agreed can mitigate the risk of losses. Mixing may either be carried out on the rig or in town, just as long as such approved additives or combinations of materials are used. During planning, the potential functions for which pills may be required should be identified and an approved list of additives and reclamation techniques established.

Non-intentional contamination originating on surface is mainly from other fluids held on the rig, water, or solids left over from the drilling operation. Clearly the best way to manage these risks is by rigorous preparation of the rig and the preventative measures and procedures for surface handling of the brine. Just as brine in surface pits must be continually monitored for surface losses, it must also be checked for ‘gains‘ of water, foreign fluids, or solids.

Full assessment of the contamination risk from the well bore operations requires detailed analysis of the completion program and, in the case of open hole completions or work-over operations, know ledge of the reservoir characteristics.

With awareness of the type and extent of down-holecontamination of the brine, the potential for resultant losses can be managed by again establishing clear guidelines for analysis, return (separately from clean brine if feasible), and reclamation. Specifically, methods for dealing with hydrocarbons, rust, and dissolved scale should be established and agreed.

Cesium potassium formate displacements – case historiesWell 1Drilling fluid: Synthetic-based mudCompletion fluid: Cesium / potassium formate Formate density: 1.90 s.g. / 15.86 ppgMeasured depth: 7,353 m / 24,124 ftTVD: 3,450 m / 11,319 ftMaximum deviation: 77°

Displacement sequence into the hole: SBM ––> WBM ––> formate brine

Detailed sequence:1. 5.0 m3 / 32 bbl synthetic-based oil.2. 14.0 m3 / 88 bbl 1.85 s.g. / 15.4 ppg WBM spacer

with 2 m3 surfactant blend.3. 246.0 m3 / 1,555 bbl 1.85 s.g. / 15.4 ppg sacrificial WBM.4. 12.5 m3 / 79 bbl 1.53 s.g. / 12.8 ppg potassium

formate brine with 1 m3 / 6.29 bbl surfactant.5. Circulate and filter 373 m3 / 2,346 bbl cesium /

potassium formate brine at 1.90 s.g. / 15.8 ppg until solids level dropped below 0.25%.


V E R S I O N 3 – 1 0 / 0 8


P A G E 1 1S E C T I O N C 1

Well 2Drilling fluid: Synthetic-based mudCompletion fluid: Cesium formateDensity: 2.19 s.g. / 18.28 ppgMeasured depth: 6,446 m / 21,148 ftTVD: 5,503 m / 18,054 ftMaximum deviation: 45°


Conventional circulation – detailed sequence: SBM ––> WBM

1. 28.0 m3 / 176 bbl SBM.2. 46.5 m3 / 292 bbl 2.16 s.g. WBM spacer with

5% surfactant.3. 10.3 m3 / 65 bbl 2.16 s.g. / 18.0 ppg WBM spacer.4. 32.1 m3 / 202 bbl 2.16 s.g. / 18.0 ppg WBM

spacer 5% surfactant.5. 30.0 m3 / 188.7 bbl WBM 2.16 s.g / 18.0 ppg.

At this point, all SBM was out of the hole and spacers 2 – 5 remained in the well, while the surface system was cleaned of SBM residues. Conventional circulation – detailed sequence: WBM ––> cesium formate

1. 38.4 m3 / 242 bbl WBM 2.16 s.g. / 18.0 ppg.2. 20.0 m3 / 125 bbl surfactant spacer.3. 6.0 m3 / 38 bbl viscosified cesium formate at

2.19 s.g.4. 133.2 m3 /838 bbl cesium formate brine at 2.19 s.g.

/ 18.3 ppg representing an over displacement of 28.2 m3 / 177 bbl before 2.19 s.g. / 18.3 ppg returns were seen at surface.

Following the displacement, clean up to 16 ntu took a further six hours of circulation.

Displacement sequence out the hole: Cesium formate ––> potassium formate ––> seawater

This was a two-stage displacement to avoid excessive differential pressure between the tubing string and the annulus, since this could have prematurely set the SAB-3 packer in the completion string.

Reverse circulation – detailed sequence:1. 4.0 m3 / 25 bbl viscosified potassium formate

spacer.2. 83.0 m3 / 522 bbl potassium formate brine.3. Filtered inhibited seawater.

Well 3Drilling fluid: Oil-based mudCompletion fluid: Cesium formate

Density: 2.19 s.g. / 18.28 ppgMeasured depth: 5,631 m / 18,474 ftTVD: 5,630 m / 18,470 ftMaximum deviation: 4.5°


Detailed sequence:1. 25.0 m3 / 157 bbl low viscosity SBM.2. 39.0 m3 / 245 bbl WBM surfactant spacer with

5% surfactant.3. 10.0 m3 / 63 bbl WBM spacer.4. 28.1 m3 / 177 bbls WBM flocculant pill with

5% surfactant.5. WBM at 2.16 s.g. / 18.0 ppg.

Circulation at 600 l/min / 160 gpm and 34.5 MPa / 5,000 psi maximum pump pressure to reduce risk of losses to exposed perforations. 6. 19.0 m3 / 120 bbl WBM surfactant spacer with

5% surfactant.7. 9.2 m3 / 58 bbl viscosified cesium formate.

Displacement rate 780 l/min / 206 gpm and 31.7MPa / 4,600 psi maximum pump pressure.

Displacement sequence out of the hole: Cesium formate ––> potassium formate ––> seawater

Reverse circulation – detailed sequence:1. 9.0 m3 / 57 bbl viscosified potassium formate

spacer.2. Filtered potassium formate brine.3. Filtered inhibited seawater.

Displacement rate 305 l/min / 81 gpm restricted due to the presence of the SAB-3 packer.

On wells 2 and 3, contamination due to channelling of one fluid into another occurred, both on displacements into and out of the hole. This was caused by:1. Presence of open perforations caused ECD

restrictions on the pump rate.2. Barite sag, compounded by channelling due to

the low pump rate, which even a high viscosity spacer did not wholly eliminate.

3. Restrictions on the maximum pump rate allowable on displacing the cesium formate out of the hole due to concerns about prematurely setting the SAB-3 packer.

TrippingIn this context, tripping is taken to include the movement in or out of the well of work-strings, completion assemblies, tubing, and wireline tools. Most of the (avoidable) losses in the past tended


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S E C T I O N C 1

to occur whilst tripping tubulars, especially with packers. These losses happened during tripping in and out, although they tended to be worst when tripping in. Often the brine was lost via back flow from the tubing on the rig floor. Some of this is caused by hydrostatic variations between the fluid in the annulus and the fluid in the tubing, which in turn is usually caused by the effect of temperature variations on effective brine density. For example on tripping out, cold, denser brine from the trip tank is used to keep the well full. On other occasions, running speed while tripping may be a factor, especially with packers in the string where tight clearances may be present. On some rigs the rig floor drains can be directed back into the flowline.

Note: If back flow is being experienced, both the addition rate for annular top-up

fluid and / or pipe running or pulling speed should be urgently reviewed. Incorporating a LaFleur type packer in the tubing fill up

assembly has proved effective in controlling back flow, but this may slow

down the running speed.

Typically, the two most common techniques used to attempt to combat losses from back-flow are the use of heavy, cold slugs of brine while pulling out, or attempts to homogenize density by circulating. Unless viscosified, brines do not usually require heavy pills to be pumped when tripping out. The most common exception to this is when the brine density in the system is out of balance. If this is the case, then at least one string capacity of brine should be pumped prior to pulling out. This ensures that any light spots are in the annulus. Also, this fresh brine is colder and hence denser than the brine in the annulus, even if the brine system has an even weight against the reference temperature of 15.6°C / 60°F.

Note: After trips any light brine should be directed to a separate light brine pit.

If flow-back is experienced or likely when running in, e.g. when running packers or 3 1/2" pipe into 6 5/8" casing, a LaFleur type packer may be screwed onto the top of each stand as they are run to prevent back-flow. Any trapped pressure is bled off prior to removing the cap to make the next stand. The brine should be bled off into a suitable con-tainer (MPT) for return to the system. When pipe is being pulled, the use of a saver barrel is highly recommended.

C1.3.5 Sub-surface

Brine jobsIn the wells reviewed where heavy brine was lost downhole, the losses fell into two main categories – brine left below the production packer and brine lost during well kill operations. In cased and perforated completions, losses downhole primarily consist of the volume below the production packer. In fact, most of this fluid returns to surface when the well is flowed and is lost through the production equipment. The packer setting depth and well geometry determine its volume, which in respect of the risk of brine losses are ‘givens’. Whilst it may be feasible to displace it out (for example using coiled tubing) prior to perforation, it may not be economically or technically advisable to do so. Any fluid left in the hole, as temporary or permanent packer fluid, should not be counted as lost sub-surface since, in theory, it is recoverable.

In production wells, brine lost during well kill operations is either a consequence of severe problems on the completion, or a result of a need to work over a previously completed well. The common factor is that the brine column is in communication with the reservoir. Knowledge of reservoir conditions – temperature, pressure and fracture gradients, permeability, and the likelihood of natural fractures being present – along with detailed review of the completion design and program, will identify when risk of down-hole losses to the formation is present. These may occur, for example, upon perforation or pulling of production or testing packers.

Each of these potential loss situations should be reviewed to establish whether the risk can be avoided or mitigated, and what agreed contingency plans should be set up when using LCM, brine density adjustment, and desirable safety stocks of brine. In respect of prevention and treatment of downhole losses, formate brines, under the temperature and pressure conditions probable in wells where they are used, do not present any peculiar technical challenges. Indeed, because of the relative ease with which they may be viscosified, for example, they may offer advantages over alternative brines.

Note: As with all high-density brines it is important to adjust the density (as

measured on surface), for the down-hole conditions of temperature and pressure

to secure well bore pressure control, without subjecting the formation to excessive hydrostatic pressures.


V E R S I O N 3 – 1 0 / 0 8



Due to the low viscosity of formate brines, dynamic and transient pressures experienced whilst circulating, tripping, or working pipe are lower than with more viscous alternatives, such as zinc bromide. Therefore, where the reservoir is exposed to these pressures, the risk of induced losses is decreased.

Following assessment of the risk of sub-surface losses, and after loss avoidance and mitigation measures have been exhausted, a detailed response plan must be formulated and communicated, covering agreed procedures, materials, and responsibilities. A lost circulation pill formulated for the reservoir should effectively stop fluid loss without permanently sealing the formation flow channels. In essence, the pill comprises bridging agents in a viscous carrier fluid, which is non-damaging to the productive formation.

The type of formation being completed influences the choice of bridging agent and viscosifier. For losses in reservoirs which are not acid sensitive, calcium carbonate or ground marble may be used as a bridging material to seal off loss zones. At temperatures below 170ºC / 338ºF (depending on formate brine type and concentration – see Section B5) Xanthan gum can be used to viscosify brine pills to carry the bridging material. At higher temperatures, other high-temperature polymers can be used, such as 4-mate-vis-HT. The pill should be spotted over the area of loss, allowing the formation to seal by the naturally occurring differential hydrostatic pressure and not squeezed. Assuming the average permeability of the reservoir is known, suitably sized material should be carried for dealing with seepage type losses, along with coarser material for more serious losses to fractures. If losses are being experienced and a reduction in fluid hydrostatic is acceptable, the

remedial pills should be mixed in the cheaper, but compatible, potassium formate.

Table 2 provides suggested outline formulations for dealing with losses of varying degrees of severity. The grade(s) of calcium carbonate chosen are influenced by reservoir characteristics and loss severity. For example, as a bridging agent for seepage losses, approximately ten percent of the bridging material should have a particle size at least one third of the average pore diameter, with the balance coming from the next grade higher. Drilling fluid jobsLost circulation is one of the most common and expensive problems encountered in a drilling operation. If not handled properly it may cause or contribute to other problems, such as kicks or formation damage. The financial consideration is of a greater significance when using high-density formate-based mud.

The undesirable effects of lost circulation include:1. Lowering of the fluid level in the annulus. This

can result in the hydrostatic pressure becoming lower than the pore pressure of other exposed formations, which allows entry of formation fluids into the wellbore. This can, at worst, result in an underground or surface blow out.

2. Absence of information about the drilled formation in the case of total loss of returns.

3. Stuck pipe and expensive fishing or sidetrack operations.

4. Formation productivity impairment.

Lost circulation can be simply defined as being the loss of whole fluid or cement to the formation during drilling or cementing operations. For this to occur, two conditions must exist:1. The pressure exerted by the fluid column either

Table 2 Suggested formulation for losses of varying degrees of severity.

Loss typeLoss rate

Viscosifier (depending on temperature)Calcium carbonate

Xanthan gum 4-mate-vis-HTm3/hr bbl/hr kg/m3 ppb kg/m3 ppb kg/m3 ppb

Seepage 0 – 1.5 0 – 10 2.8 – 5.7 1.0 – 2.0 22 – 45 8.0 – 16.0 15 – 30 5 – 10

Moderate 1.5 – 5 10 – 30 2.8 – 5.7 1.0 – 2.0 22 – 45 8.0 – 16.0 60 – 90 20 – 30

Severe > 5 > 30 2.8 – 5.7 1.0 – 2.0 22 – 45 8.0 – 16.0 140 – 430 50 – 150

Table 3 Types of drilling fluids losses.

Loss Type Rate (m3/hour) Comment

Seepage < 1.5 Hole remains full with pumps off

Partial 1.5 – 3.0 Hole remains full with pumps off

Severe > 3.0 Hole may or may not remain full with pumps off

Complete No returns No returns with pumps – hole will not stand full with pumps off


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S E C T I O N C 1

while static or during circulation must exceed the formation pore pressure.

2. The porosity and permeability of the formation must be large enough to allow the passage of whole fluid thus preventing the sealing effect of the filter cake. Experimental evidence suggests that these openings must be three times larger than the diameter of the maximum particle size found in quantity in the fluid.

Losses can result from either natural or induced causes.

Losses of whole fluid to the formation have been arbitrarily divided into the following classifications:

Permeability and bridgingFormation pores where whole fluid is lost must be about three times larger than the largest particle size found in the mud. Since most drilling muds contain at least some solids of up to 100 microns, a formation must typically have permeability in excess of 10 Darcy for whole mud to be lost. Therefore, this type of loss is practically confined to gravels and coarse sands near surface. Porosity and permeability generally decrease with depth and deep sands do not usually have permeabilities greater than 3 – 4 Darcy, and have to be fractured in order to take whole fluid.

To put these comments into context, if it is considered that the d50 of a formation pore size is approximately equal to the square root of that formation’s permeability (in mD), then a formation with a permeability of 3 Darcy has a median pore size of 55 microns. Drilling muds typically contain a solids distribution from the sub-micron up to 100 microns and can therefore be considered to contain sufficient bridging solids to prevent losses to most deep formations, unless natural or induced fractures are present.

Typical formate drilling fluid formulations are listed in Table 4. If lost circulation occurs, it is best managed and cured with a consistent approach to recording and reporting the event. The following should be included:1. Static loss rate in bbl or m3 per hour.2. Dynamic loss rate in bbl or m3 at the applicable

flow rate.3. Maximum loss free pump rate and calculated

ECD at that rate.4. Depth (measured and total vertical).5. Note if the losses build up to the stabilised rate

gradually or occurred suddenly. This is helpful for distinguishing losses to pores, which only require fine LCM, or losses into fractures, which can require coarser grades.

6. Determine the source by first eliminating surface possibilities. If losses start while drilling, the loss zone is likely to be on bottom; if losses occur while tripping in the hole then it is likely that the loss zone is off bottom.

Prior to adding any LCM to the mud or pumping LCM pills, the size and type of LCM to be used should be discussed with the operators of any downhole tools (MWD, LWD, motors, etc.) to ensure that these do not become blocked.

Note: If the well kicks as a result of a loss of hydrostatic pressure due to lost

circulation the priority is always to control the kick before dealing with the losses.

Reducing mud weightsWhen lost circulation is encountered, if reducing the ECD by slowing the pumps does not cure the problem then, if possible, the mud weight should be reduced.

The use of LCM without reducing mud weight may, in some circumstances, be counterproductive as it

Table 4 Typical drilling fluid formulation and properties.

FormulationConcentration

Properties Units[kg/m3] [ppb]

Cesium formate brine 2.30 s.g. / 19.18 ppg 0.50 0.175 Density (@15.6°C / 60°F) 1.95 s.g / 16.3 ppg

Potassium formate brine 1.57 s.g. / 13.09 ppg 0.50 0.175 Plastic viscosity 20 cP

Xanthan gum 4.0 – 5.0 1.40 –1.75 Yield point 15 lb / 100 ft2

PAC LV 7.5 – 12.5 2.63 – 4.38 Gel strengths 5/8/12 lb / 100 ft2

Modified starch 7.5 – 12.5 2.63 – 4.38 API fluid loss 0.5 – 2.0 mL

Potassium carbonate 2.0 – 4.0 0.70 – 1.40 HPHT FL (125°C) 7.5 – 10.0 mL

Calcium carbonate 50 – 75 17.5 – 26.3 pH 9.5 – 10.5

Drilled solids 2.5% v/v 2.5% v/v MBT 2.5 – 10.0 kg/m3


V E R S I O N 3 – 1 0 / 0 8



can act as a propping agent and prolong the problem by holding fractures open. However, as the pressure required to propagate a fracture is normally less than that to initiate it, it usually is unfeasible to reduce the equivalent mud weight to a value below the fracture propagation pressure.

An estimation of the maximum mud weight that the formation can stand is obtained from the method described below.1. If there are returns, fill the annulus with a measured volume of water and calculate the

new gradient.2. If there are no returns, attempt to circulate at

the same pump rate that was in use prior to the losses occurring and compare the circulating pressure AP

BP

MWPP

h BAOH

−=

OHh

AP

BP

MW

)(

)(cos)(2ftaSurface are

cPityVisgpmFlow rateyFlow densit

×=

prior to the losses with the circulating pressure

AP

BP

MWPP

h BAOH

−=

OHh

AP

BP

MW

)(



×=

after:

where

AP

BP

MWPP

h BAOH

−=

OHh

AP

BP

MW

)(



×=

= Height of empty hole (m or ft)

AP

BP

MWPP

h BAOH

−=

OHh

AP

BP

MW

)(



×=

= Circulating pressure prior to losses (bar or psi)

AP

BP

MWPP

h BAOH

−=

OHh

AP

BP

MW

)(



×=

= Circulating pressure after losses (bar or psi)

AP

BP

MWPP

h BAOH

−=

OHh

AP

BP

MW

)(



×=

= Mud weight (bar/m or psi/ft)

If the position of the loss zone is known a new mud gradient can be calculated to balance the weak formation.

Lost circulation in typical tight reservoir rocksIf an average permeability range of a typical tight reservoir rock (a few millidarcies up to 1 Darcy) is considered and the mud solids are of typical particle size distribution, significant whole fluid losses are considered unlikely unless inadvertent hydraulic fracturing of the formation occurs.

The risk of hydraulic fracturing is reduced with formate fluids since hydraulics simulations and field experience have shown that ECDs (and transient pressures) are lower for any given pump rate, than for conventional solids-weighted mud. Nonetheless, the possibility cannot be completely ruled out. In addition, there is also the risk of losses to natural fractures or faults in the reservoir. Therefore, planning needs to address the whole range of possibilities – from seepage losses to total loss of returns.

Seepage to partial lossesTable 3 defines seepage to partial losses as being up to 3 m3 per hour. With formate-based fluids in the hole, economics demand that the losses are dealt with well before the upper limit of that range has been reached.

Although formate fluid systems contain a much lower volume of solids compared to an equivalent weighted OBM or WBM (5 – 8% as opposed to > 30%), they contain solids (graded calcium carbonate) that have been specifically sized to minimize seepage losses by bridging off on the sand face. Because the actual PSD of the solids in the mud varies during drilling due to removal by surface equipment and mechanical degradation, adding calcium carbonate is the first option to control minor seepage losses.

Higher spurt losses may be experienced as high permeability channels are intersected, but even these should be quickly bridged off by a competent filter cake. During drilling of the reservoir, if an increase in downhole losses is observed, pills containing an increased concentration of calcium carbonate (of the sizes in use in the fluid as a whole) may be pumped. To avoid completion damage (by plugging screens on back flowing the well), this approach is recommended in the first instance rather than pumping pills containing coarser material.

Use of high viscosity pills containing increased concentrations of the calcium carbonate used in the fluid are recommended along with reductions in the pump rate to deal with more severe losses.

C1.3.6 Brine recovery and return

Back load from the rigWhen the completion operation is over, all cesium formate brine fluid not left in the hole as a packer fluid is returned to the supply boat. Most will be in bulk, pumped from the rig tanks, although some contaminated fluid, such as interfaces, may be returned in MPTs. As far as possible, fluids of different densities should be back loaded separately, and the back load plan should address this issue and allocate specific tanks on the supply vessel for the different batches. In particular, unused reserve volume should be kept separate from used brine.

The disposition and respective volumes of fluids loaded on to the supply vessel must be promptly communicated to town so that preparations can be made to receive them. Prior to pumping, the vessel engineer should, if possible, visually inspect the receiving tanks and confirm that they are clean to brine standards. The fluid engineer should ensure that the supply boat engineer is fully aware of the nature and value of the cargo. Loss risk ‘ownership’ passes to the vessel engineer after back loading is complete. All personnel involved must understand the pumping sequence and the lines of communication and control.

To completely clear the rig of completion brine, each pit or storage tank should, in turn, be

AP

BP

MWPP

h BAOH

−=

OHh

AP

BP

MW

)(



×=

(1)


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S E C T I O N C 1

transferred to the pit with the lowest suction line to reduce dead volume. When all pits / tanks are emptied as much as possible (preferably using the dedicated surface transfer system mentioned previously, rather than the permanent rig piping), pumping to the boat should be suspended. The remaining volumes should be transferred using a diaphragm pump to one pit (usually a slug or pill pit with the smallest dead volume). This fluid may be pumped to the boat or to a MPT. As when loading, care should be taken to recover any volume remaining in the hoses. Samples must be taken of all back-loaded fluid(s) for comparison with samples taken when the brine is received into the onshore tanks.

Onshore receiptOn arrival onshore, samples are taken from the boat tanks and volume in each tank checked. The fluid is then pumped either via road tankers or directly into prepared, clean, and secure holding tanks for sampling, analysis, and reclamation. Vacuum pumping equipment is used in the vessel tanks to recover residual fluid that the vessel pumping system cannot reach. Again, care should be taken to recover fluid in transfer hoses and lines, both in the plant and on the vessel. An independent surveyor should be present along with the representative of the mud or brine company, or Cabot Specialty Fluids. The samples are analyzed and compared with the specification of the fluid supplied and, based on this, a reclamation program agreed.

C1.3.7 Brine reclamation

Brine reclamation may be defined as the removal or ‘neutralization’ of contaminants, intended to restore the brine, as far as is practicably possible, to its original specifications. These contaminants include particulate matter, precipitates, dissolved ions, and other liquids, such as water or oil. Reclamation may result in net volume loss from:

• Removalofinsolublesorprecipitatesbyfiltration• Removalofwaterbyevaporation• Removalofoilbymechanical separation However, it can also result in a net volume gain – for example where dry salt or ‘spike’ fluid is added to regain density after contamination by water.

Removal of insolubles and precipitates by filtrationInsolubles or particulates include mud solids, precipitates, rust products, polymers, scales, pipe

dope, etc. The factors that influence filtration efficiency are as follows: • Thefiltrationprocess–DEorcartridge• Thebrinecleanlinesscriteria–absoluteor

nominal• Thephysicalcharacteristicsofthefluid–density,

viscosity, TCT, etc.• Thephysicalcharacteristicsoftheinsolubles

– quantity, PSD, surface area• Theskillsandexperienceofthefiltrationoperators

Filtration processesThe two methods of filtration commonly used in the oil industry are the diatomaceous earth (DE)1 filter press and cartridge filter units. Generally, the former is considered more cost efficient as, for any given level of contamination, throughput rates are higher and consumable costs are lower. However, other things being equal, loss of fluid may be higher with a DE unit than with a cartridge unit. With low value brines the economics favor the use of DE units, but with high-value cesium formate brines the position is reversed. The costs associated with the lower filtration rates (time) and the higher cost of the filtration media (cartridges), will be more than offset by the reduced losses of brine. Even in the most modern of DE filter presses equipped with air blow down systems, the volume of brine lost is equivalent to 20 – 30% of the volume of DE used during filtration, excluding extraneous losses in the plumbing. This is fluid lost by adsorption onto the diatomaceous earth or held in the interstices of the filter cake formed by it during the filtration process. Serial filtration, involving either a DE unit followed by a 2 µm (A)2 cartridge unit, or a 10 µm cartridge filtration followed by 2 µm (A) filtration, may be cheaper in filtration consumable terms, but can result in higher collateral brine losses. While it is difficult to obtain reliable comparative data, filtration industry experts consulted confirm that, other things being equal, loss of volume is significantly lower with cartridge units. However, notwithstanding the above, experience with cesium / potassium formate brine reclamation has shown that for heavily contaminated brine it may be necessary to use DE filter press equipment. With good preparation and stringent loss prevention procedures it is possible to achieve recovery rates of 95% of the liquid fraction of heavily (12.7% by volume) solids-contaminated cesium / potassium formate brine using this equipment.

1) Alternatives to DE, such as Perlite, are used on some occasions due to HSE restrictions.

2) (A) – absolute rating is an indication of the largest pore opening in the media.


V E R S I O N 3 – 1 0 / 0 8



Brine cleanlinessClearly, brine cleanliness criteria influences the volume lost during filtration. There are two criteria for brine cleanliness – one qualitative and one quantitative. The former specifies a maximum size of solid that remains in the fluid after filtration, e.g. a fluid filtered through a 2 µm absolute filter cartridge will (theoretically) contain no solids greater than 2 microns. The quantitative criterion specifies the maximum quantity of solids, e.g. < 1,000 ppm or 0.1% by volume.

Physical characteristics of the brineSome of the effects of a brine’s physical characteristics on filtration efficiency are fairly straightforward. Obviously, as density and viscosity increase the ability of a fluid to suspend solids also increases. Consequently, removing these solids becomes more difficult. Flow rates through the filtration system reduce and fouling of the filtration media increases. Associated loss of fluid is higher due to a greater adsorption propensity of the brine onto the removed solids. Any viscosity imparted to the brine by the use of polymeric viscosifiers must be reduced by the use of breakers prior to filtration. In low temperature (winter) conditions it should be noted that the presence of particulates might increase the brine’s crystallization temperature. Any precipitation of solid salt affects the filter media life as well as reducing the fluid density and increasing volume loss.

Physical characteristics of the solidsThe following effects of the solids to be removed need to be considered:

• Thequantityofsolidsinthebrine• Theparticlesizedistribution,shape,andsurface

characteristics• Particleadhesiveness• Particlecompressibility• Intensityandpolarityofelectrostaticchargeson

the particles relative to those of the filter media These factors determine the filter cake formation rate and permeability during the filtration process, which in turn affects the efficiency of the process, both in terms of solids removal and filtration media

longevity. In cases of very high solids loading it may be advantageous to dilute with clean brine to improve filtration efficiency.

Flow densityOne useful measure employed in the filtration industry to measure filtration efficiency is flow density, which is defined as follows:

AP

BP

MWPP

h BAOH

−=

OHh

AP

BP

MW

)(



×=

Filtration efficiency is improved by lowering flow density which, as shown above, is achieved by reducing flow rate, increasing surface area (of the filter media), or decreasing viscosity. Volume reduction from filtration is primarily influenced by the following factors:

• Thequantityofinsolublesremoved• Theeffectivesurfaceareaoftheinsolubles

removed• Theviscosityofthebrine• Theefficiencyofthefiltrationprocessin minimizing intrinsic and collateral losses

Although the first two may be relatively insensitive to manipulation intended to reduce losses by increasing filtration efficiency, the latter two are, to a degree, controllable.

Removal of dissolved ions and polymersTypically in the reclamation process, prior to filtration, chemical treatments are made in order to precipitate dissolved ions and reduce the viscosity by breaking polymers. A number of issues need to be addressed in this area, since techniques that work in conventional brines may not be applicable for formate brines, e.g. oxidizers like hydrogen peroxide, which are used to break polymers, are not compatible with formate brines. In respect of dissolved ions, it is important to be clear about which ones at what levels constitute a real, rather than a perceived, problem. Formate brines see repeated cycles of use and levels of potentially troublesome ions, such as chlorides and divalent ions like barium and calcium, build up unless effective removal techniques are applied.

Table 5 Treatment of common contaminants.

Contaminant Treatment

Most cations and polymers Raise pH with hydroxide

Sulphate Barium formate

Sulphide Ironite sponge

Calcium Potassium carbonate

Chlorides Can be removed using silver salts


P A G E 1 8 V E R S I O N 3 – 1 0 / 0 8


S E C T I O N C 1

The basic removal strategy developed originally by Shell [4] and applied with varying degrees of success on potassium formate brines and muds involves raising the pH of precipitate polymers and divalent ions (as their hydroxides). Experience with this has shown it to be effective for most divalent cations (with calcium the main exception). Other contaminants, such as calcium or sulphate, can be removed by additional treatments. These should be applied on a case by case basis. A summary of the treatment for common contaminants is given in Table 5. In practice, it is often most economical to dilute with uncontaminated fluid to maintain contaminants at or below acceptable levels.

Removal of water by evaporationConventional reclamation approaches either accept the presence of water, and simply reduce the value of the brine accordingly, or add dry salt or dense spike fluid to neutralize its effect on the brine density. Alternatively , it is possible to use evaporation devices to remove excess water and restore brine density – indeed this is an integral part of the production of cesium and potassium formate brine in the first place. In practice, this is rarely if ever done with conventional halide brines. However, it is routinely done in the reclamation of water-contaminated cesium / potassium formate brine. In particular, where contamination comes from low chloride water, such as drill water, this reclamation method may be more economical than either of the conventional approaches. If the contaminate is seawater, evaporation does not remove dissolved ions, such as chlorides, but concentrates them instead, which may be undesirable.

Removal of oil by mechanical separationOil-water separation is a problem that has plagued the oil industry for decades, with many new and novel approaches tried over the years. Most of these approaches have been based on manipulation of one or more of the parameters of Stokes Law. An example is the use of hydrocyclones, which exploit the difference in density between oil and water, and use centrifugal force to separate the two fluids. Various membranes have also been tried, together with absorption and adsorption materials. In the context of brine reclamation, contamination with oil has typically resulted in serious loss of brine, since the presence of oil dramatically reduces the efficiency of conventional filtration.

Brine returned for reclamation containing even low quantities of oil is usually left static for a period to allow the oil to rise to the top (Stokes Law). The lower fraction is then pumped out and filtered and the upper fraction dumped. Normally, even the lower fraction still contains some oil, especially if

the brine also contains colloidal solids that have an emulsification effect. As a result, even filtration of this portion is inefficient, requiring frequent changes of media and proportionately high loss of brine. A recent review conducted by a specialist filtration company concluded that for this application the adsorption approach offers the most cost-effective method of cleaning brine with low concentrations of hydrocarbons. Briefly, the process of adsorption is one in which the hydrocarbon molecule is chemically bonded to a receptor site within an adsorption medium. The medium proposed is cellulose based with fibers treated and coated with a chemical that encourages hydrocarbon molecules to adsorb. The adsorption material is made in cartridge form to facilitate handling and changes of use. Various types of filter housing are available that accepts the cartridge.

The process that takes place within the unit is similar to filtration with one exception. Instead of physically interrupting the flow of solid particles and trapping them in a porous medium the hydrocarbon droplets, when they collide with the adsorption material, chemically bond to it and cannot be removed. The system removes dissolved as well as undissolved oil. The process is claimed to operate at most normally encountered temperatures, and throughput rates vary with the number of cartridges in place. The adsorption material is said to be unaffected by water or brines. In testing, the efficiency of the process has been shown to be good, with 90 to 95% removal in one pass, where the oil in water content is less than 1% by volume. Higher concentrations require a re-circulating system to reduce the oil to acceptable levels with multiple passes.

Losses during reclamationClearly the main area where physical loss of fluid occurs is during the filtration process. Loss minimization input and subsequent ‘ownership’ of the process, both onshore and offshore, must be secured from the filtration contractor. Where technically feasible, filtration should only be carried out once, rather than once when removing suspended solids and again after the addition of precipitants and other reclamation agents is complete.

It is thought that cartridge units offer the lowest media losses and reduce the amount of collateral losses, but may only be effective for lightly contaminated brine – less than 1.5% by volume solids. Hoses should be fitted with ball valves, which prevent loss of brine when they are disconnected during maintenance, repositioning, or rigging down equipment. Portable trough or


V E R S I O N 3 – 1 0 / 0 8



catch trays at the disconnect points may be useful. Attention to detail during filtration operations reduces losses and offers maximum recovery of valuable fluid.

All proposed treatments should be assessed on their costs and benefits against the value of using the brine in the future, particularly where a customer commits to re-using the fluid on a series of wells. In such a case, the user may elect not to return the fluid fully to original specification until the conclusion of the multi-well project.

C1.4 Summary – the life cycle of a formate brine fluid

Prepare brine for supply1. Prepare and blend in secure, dedicated,

and clean tank system.2. Transport and transfer in clean, secure

equipment.3. Sample and accurately record volumes, and density.

Prepare rig for receipt1. Prepare, clean, and secure storage tanks at

the well site.2. Check and eliminate all potential sources of

leaks and contamination.3. Prepare detailed off-loading plan.

Receive and store brine on rig1. Implement off-loading plan and record volume

and density received.2. Use dedicated transfer and mixing system.3. Minimize movements of brine on surface.

Displacement1. Co-ordinate and communicate plan.2. Clean well bore, rig fluid lines, and tanks.3. Prepare spacers.4. Condition fluid in hole if displacement is direct.5. Displace using appropriate circulation direction.6. Monitor returns, keeping well bore fluid, spacer,

and brine separated.

Condition brine in well1. Adjust density.2. Filter until required specification for clarity and

cleanliness are met.3. Filter as required while working with brine in well. Tripping 1. Use appropriate running speeds to eliminate

flow back.2. Use heavy slugs or displace string to cold brine

as required.3. Monitor volumes closely.

Displacement of brine from well1. Co-ordinate and communicate plan.2. Prepare and pump spacer between brine and

displacement fluid.3. Displace brine to prepared clean and secure

storage tanks.

Recovery of used brine1. Transport and transfer in clean, secure

equipment.2. Store in well prepared, clean, and secure

storage tanks at the onshore facility.3. Sample, analyze, and pilot test reclamation

treatments required before filtering.

Reclamation1. Add KOH as appropriate. Mix thoroughly, but

without violent agitation.2. Allow treated brine to remain quiescent for the

time necessary for separation and settling as determined by the pilot tests.

3. Filter fluid:a) Filter clear portion of fluid first.b) Filter flocculated portion until cost, in terms of

disposables or related time, exceeds the value of the fluid being recovered.

c) Dispose of waste in accordance with relevant disposal regulations.

d) Store clean fluid in a clean, secure, and dedicated storage facility.

C1.5 Fluid sampling

A standard protocol for movements of cesium / potassium formate brine is recommended where, at each movement, three sets of samples are taken from each batch, shipping container, or tank.

• Onesetforcustomerreference• OnesetforCabotSpecialtyFluids• Onesetforthemud/brinecontractor The purpose of the samples is to verify the condition of the fluid at the various stages in the cycle of supply, utilization, and return. Should any problem occur that affects the condition or value of the brine, the sampling regime helps to guide the investigation into cause.

Sample containers of 0.5 liter are sufficient. The following information should be included on the label: • Customername• Sampledateandtime• Wellidentification• Samplesource–plant,rig,vessel,truck,etc.• Samplepoint• Samplefluiddescription,density,andtemperature


P A G E 2 0 V E R S I O N 3 – 1 0 / 0 8


S E C T I O N C 1

On shipping to the well site, samples should be taken from each loaded tank. When returning fluid to shore, samples must be taken of each individual batch back loaded, either in bulk form or in Marine Portable Tanks. Fluid being displaced from the well bore should be sampled at least three times – at the beginning, middle, and end of the displacement.

References

[1] “Review of ZnBr2 & CaBr2 Losses in HTHP Well Testing Operations”, Appendix 2 of “Cesium Formate Loss Management – Version 2.0”, Cabot Specialty Fluids document, 1997.



[4] Howard S.K. et al.: “Formate Drilling and Completion Fluids – Technical Manual”, Report # SIEP 96-5091, Shell International Exploration and Production, August 1996.


V E R S I O N 3 – 1 0 / 0 8



Appendix 1 Checklist

General

Perform Total Containment Rig audit prior to start of contract

Avoid BOP testing during formate operations if possible. If testing is required then test

with formate, do not displace to seawater

Check riser slip joint

Major unavoidable losses are below packer; from displacement and during reclamation

expect 10% overall

Major avoidable losses are incurred during surface handling

Discharge

No discharges without first consulting town on cost benefit of reclamation

Pit room

Double valve isolation

Gate valves as opposed to butterfly

Minimum number of pits

Minimum number of transfers

Dump valves should be hydrotested, pad locked, and controlled under a PTW

One dedicated mix line

Isolate seawater and drillwater lines in pit room

Drain mix lines as opposed to flushing with water, blow through with rig air, if drain valve

not present then install one

Test all valves in pit room, i.e. pump against them in the closed position

Pit and trip tank dead volume recovery to tote tanks – diaphragm pumps and hoses

available

Pits and tanks cleaned to brine standards

Steam cleaner for pit cleaning

Silicone sealant can be used on gates, dump v/v, and equalizer v/v

Pump room

Install drain valve on main suction. This will minimize contamination and optimize

recovery

Rig vac for recovery of spills

Pump packing – check for leaks and re pack as required

Brine transfers

Purchase of new hoses, install flotation aides

Pressure test hoses prior to delivery

Cabot Specialty Fluids engineer to supervise supply boat to rig transfers

Transfer in daylight if possible

Pre-job meeting with telephone or radio hook up to vessel engineer

Cross check delivery every 50 bbl

Do not use brine tank if possible, transfer direct to pits

Minimize number of transfers

Flush lines with water, drain, and blow through with rig air prior to delivery

Have one experienced designated member of the drill crew appointed for all transfers

(for both inter-pit transfers and supply vessel to rig)


P A G E 2 2 V E R S I O N 3 – 1 0 / 0 8


S E C T I O N C 1

Pit and trip tank dead volume recovery to tote tanks – diaphragm pumps and hoses

available

Pits and tanks cleaned to brine standards

Steam cleaner for pit cleaning

Silicone sealant can be used on gates, dump v/v, and equalizer v/v

Pump room

Install drain valve on main suction. This will minimize contamination and optimize

recovery

Rig vac for recovery of spills

Pump packing – check for leaks and re pack as required

Brine transfers

Purchase of new hoses, install flotation aides

Pressure test hoses prior to delivery

Cabot Specialty Fluids engineer to supervise supply boat to rig transfers

Transfer in daylight if possible

Pre-job meeting with telephone or radio hook up to vessel engineer

Cross check delivery every 50 bbl

Do not use brine tank if possible, transfer direct to pits

Minimize number of transfers

Flush lines with water, drain, and blow through with rig air prior to delivery

Have one experienced designated member of the drill crew appointed for all transfers

(for both inter-pit transfers and supply vessel to rig)

APPENDIX 1


V E R S I O N 3 – 1 0 / 0 8



Circulation

Total containment in front of shakers

Disconnect all water hoses, including rig floor and shale shakers

Cabot Specialty Fluids engineer / mud engineer present for breaking circulation

Cabot Specialty Fluids engineer / mud engineer to walk the lines

Bypass sandtraps if degasser not required (note: Denzo tape is not compatible with

formate brine – use silicone sealant)

Bypass shakers if screening not required

Have blocking pill products ready to mix at hopper

Potassium carbonate used to maintain pH at 10.5

Pump hi vis ahead of LCM to stop LCM falling through column and plugging formation

early (critical if bullheading)

Divert light fluid and viscous spacers

Pumping cesium formate drum spike fluid is labor intensive, fluid often crystallized,

better off with sack material

Displacement

Condition mud prior to displacement

Incorporate benign dye in spacer.

Spacer separation to be 1000 ft.

Spacer density mid way between two fluids

Use of viscous spacers has been shown to be of minimal benefit and inhibits filtration

and recovery.

Displace OBM to WBM prior to formate brine.

Send OBM direct to boat if possible to minimize contamination of surface pits.

Displace to intermediate brine prior to seawater to aid recovery (reverse circulate) also

minimize shock load to casing/packer? and excessive pump pressures.

Reciprocate and rotate pipe

APPENDIX 1


P A G E 2 4 V E R S I O N 3 – 1 0 / 0 8


S E C T I O N C 1

Rig Floor

Rig floor drain recovery either by catch tank or plugging drains and use of mud gulper

(flood test the drill floor to check for leak paths)

Check system for recovery from mousehole

Check system for recovery from poor boy U tube

Tripping

Avoid pulling wet

Slug pipe from cement unit – use powder to increase weight.

Have pipe wiper for all sizes of pipe

May back flow when running open ended pipe or when running production packer on

tubing. If this is the case slow running speed.

Periodically check gate line up to trip tank. Seal gate with silicon sealant.

Check packing on trip tank pump.

APPENDIX 1


V E R S I O N 3 – 1 0 / 0 8



Installation

Appendix 2 Cabot rig audit questionnaire

Rig Fluids Audit

Rig Name

Audit Date

Cabot Specialty Fluids Limited

Cabot HouseHareness Circle

Taylor’s Business ParkAltens Industrial Estate

ABERDEENAB12 3LY


P A G E 2 6 V E R S I O N 3 – 1 0 / 0 8


S E C T I O N C 1

Installation

Rig Fluids Audit

TABLE OF CONTENTS

Pages

Introduction & Rig Systems Overview

1. Bulk Loading/Backloading System

2. Onboard Transfer/Mud Mixing System

3. Pit Room

4. Pump Room

5. Drill Floor

6. Trip Tank

7. Flowline

8. Solids Removal

9. Filtration Equipment

10. Mud Laboratory

11. Supplementary Areas

12. Recommendations

13. Rig Photographs

14. Rig Drawings and Schematics

APPENDIX 2


V E R S I O N 3 – 1 0 / 0 8



Installation

Page 1

Introduction

About the rigWho is it working for and where?Type of fluids planned for use

Rig Systems Overview

A brief overview of the systems available on the rig (pits, volumes, solids control and equipment)

APPENDIX 2


P A G E 2 8 V E R S I O N 3 – 1 0 / 0 8


S E C T I O N C 1

Installation

Page 3

Rig Fluids Audit

1. Bulk Loading/Backloading System

(a) Detail the available separate loading linesCesium / Potassium Formate mud / brine, Base Oil, Brine(s), Drillwater, Freshwater

Do any separate loading lines then use a common onboard transfer line? Yes No

Details

(b) Are bulk loading lines colour coded? Yes No

Are bulk loading lines clearly identified? Yes No

Describe

(c) Yes NoDo loading lines have automatic valves to prevent spillage into the seaupon disconnection?

Detail type and position in line

APPENDIX 2


V E R S I O N 3 – 1 0 / 0 8



Installation

Page 4

Rig Fluids Audit

1. Bulk Loading/Backloading System (continued)

(d) Yes NoIs there a valve manifold to prevent mud from being transferred from oneside of the installation to the other? There should be a valve on each sideof the installation close to the loading point and one on each side of the T-piece manifold in pump room/pit room

Are the bulk loading lines clearly identified? Yes No

Describe the system

(e) Check loading hoses for damage, cuts, wear and chafing potential during badweather. Report on condition and potential for any leakage

(f) Yes NoAre loading/backloading procedures clearly displayed in the pitroom orother suitable site?

Where?

Are these procedures correct? Yes No

Are these procedures adequate? Yes No

Yes NoAre these procedures likely to lead to a potential pollution hazard/mudloss?

Evaluate

Are the procedures adhered to? Yes No

APPENDIX 2


P A G E 3 0 V E R S I O N 3 – 1 0 / 0 8


S E C T I O N C 1

Installation

Page 5Rig Fluids Audit


(g) Does the installation have bulk fluid tanks? Number Yes No

Are these exclusively dedicated to one product? Yes No

Describe

(h) How are these tank volumes monitored?Describe

Is the method satisfactory? Yes No

If not, explain

Are the calibrations used correct? Yes No

(i) Is it possible to overfill any Column tanks? Yes No

(j) Can tanks contents be monitored for product quality? Yes No

How?

Is this satisfactory? Yes No

What is the dead volume?

Can the Column tanks be adequately cleaned? Yes No

APPENDIX 2


V E R S I O N 3 – 1 0 / 0 8



Installation

Page 6

Rig Fluids Audit


(k) Is there a common line to/from Column tanks to pits? Yes No

or dedicated lines? Yes No

Describe

(l) Acquire or draw a schematic of the bulk transfer system including Column tanks

(m) Can hoses be pressure tested? Yes No

2. Onboard Transfer/Mud Mixing System

(a) Are all lines colour coded? Yes No

(b) Are all lines clearly identified? Yes No

Describe

APPENDIX 2


P A G E 3 2 V E R S I O N 3 – 1 0 / 0 8


S E C T I O N C 1

Installation

Page 7

Rig Fluids Audit

2. Onboard Transfer/Mud Mixing System (continued)

(b) Does each mixing/transfer line serve each pit? Yes No

Is each pit served by one or more base fluid line(s)? Yes No

Is each pit served by one or more seawater line(s)? Yes No

Is each pit served by one or more freshwater line(s)? Yes No

Can each pit be pumped to cement unit? Yes No

If not, explain

Is the feed rate to each line adequate? Yes No

If not, explain

Describe the system, placing special emphasis on exceptions

(c) Yes NoIs there a mixing/transfer line, which is dedicated to just one pit or groupof pits?

What are the limitations of this line?

APPENDIX 2


V E R S I O N 3 – 1 0 / 0 8



Installation

Page 8

Rig Fluids Audit


(d) Can the transfer/mixing system be operated from the pit room or does the Derrickman haveto go to the pump room to open suction valves?

Describe the system

What is the potential risk for transfer error?

Low Medium High

What are the areas of particular concern?

Can any be modified?

(e) What is the condition of the discharge valves? Good Average Poor

Do any discharge valves leak? Yes Don’t know No

Do any require special force to open or close? Yes No

Are any handles missing? Yes No

Detail

APPENDIX 2


P A G E 3 4 V E R S I O N 3 – 1 0 / 0 8


S E C T I O N C 1

Installation

Page 9

Rig Fluids Audit


(f) How are slow transfers usually made?

Can slow transfers be metered? Yes No

Is this satisfactory for base fluid? Yes No

Is this satisfactory for high value fluids? Yes No

Is this satisfactory for Cesium Formate brine, etc? Yes No

Are there any restrictions or hindrances to making such transfers from any particular tanks?Explain

(g) Acquire or draw a schematic of the mixing/transfer system

APPENDIX 2


V E R S I O N 3 – 1 0 / 0 8



Installation

Page 10

Rig Fluids Audit

3. Pit Room

(a) Note theoretical tank dimensions and volumes. Verify if at all possible.Acquire schematic of tank layout, otherwise provide a sketch.

(b) Have the pit volume calibrations been accurately checked? Yes No

Date of last calibration

Do the pitroom calibrations match those used by the rig floor monitoringsystem?

Yes No

Describe any variations

Is there any reason to suspect one or more calibrations are incorrect?

Yes No

Explain

APPENDIX 2


P A G E 3 6 V E R S I O N 3 – 1 0 / 0 8


S E C T I O N C 1

Installation

Page 11

Rig Fluids Audit

3. Pit Room (continued)

(c) What system is used in the pit room for monitoring pit volumes?

How accurate and efficient is this method, and is there room for improvement?

(d) Has a direct volume read out system been installed? e.g. float andcalibrated pole

Yes N/A

What pits have this system?

Are they all working? Yes N/A

If not, describe why

Can the volume indicators be easily read? Yes N/A

From what distance approximately? Distance

Could all pits have the same system installed? Yes No

Is their room within the pits? Yes No

Is their room on top of the pits? Yes No

APPENDIX 2


V E R S I O N 3 – 1 0 / 0 8



Installation

Page 12

Rig Fluids Audit


(e) Does the Derrickman keep a comprehensive written record of all pitvolumes?

Yes No

Where are records kept and for how long?

Does this have a means of totalising and checking volumedifferences?

Yes No

(f) Yes NoIs there a whiteboard (or similar) for recording weight, viscosity,volume and other information so it can be regularly updated and easilyread?

Is this system used properly and updated? Yes No

(g) Are all lines colour coded? Yes No

Are all lines clearly identified? Yes No

Note any which are unclear or ambiguous

Mud Balances i. how many?

ii. pressurised? Yes No

iii. in good working order? Yes No

iv. regularly calibrated? Yes No

v. how often and by whom?

APPENDIX 2


P A G E 3 8 V E R S I O N 3 – 1 0 / 0 8


S E C T I O N C 1

Installation

Page 13

Rig Fluids Audit


(i) Can tanks overflow into each other? e.g. via a ditch Yes No

Explain

What restrictions do gates put on storage capacity?

How are ditch gates usually sealed?

Are any currently leaking? Yes No

Yes NoAre there secondary means of preventing such leakage? e.g. gatesacross the ditch.

Draw a schematic of the ditch showing positions of gates and how many gates feed eachtank

APPENDIX 2


V E R S I O N 3 – 1 0 / 0 8



Installation

Page 14

Rig Fluids Audit


(j) Would the fitting of high level alarms be justified in any of the pits? Check on the feasibility and explain

(k) Do any of the pits have equalisers? Yes No

Draw a schematic

Are they all clearly identified? Yes No

Are they all in good working order? Yes No

Describe

Describe the tank dumping system

APPENDIX 2


P A G E 4 0 V E R S I O N 3 – 1 0 / 0 8


S E C T I O N C 1

Installation

Page 15

Rig Fluids Audit


(k) continued

Tank Dumping System

Is it manual from above? Yes No

Is it manual from below? Yes No

Is it necessary to pump the contents out? Yes No

Can the contents be pumped out? Yes No

Where does dumped fluid go? Sump tank

Oil catchment tank/separator

Slop tank

Discharge to sea

Are procedures clearly displayed? Yes No

Are they adhered to? Yes No

Are dump valves always locked? Yes No

Are dump valves locked only when Cesium / Potassium Formate mud /brines / LTOBM / base oil is in use?

Yes No

Is there a master dump valve? Yes No

Is it always locked? Yes No

Is it locked only when Cesium / Potassium Formate mud / brines / LTOBM/ base oil is in use?

Yes No

Is it clearly marked? Yes No

Who retains the key?

APPENDIX 2


V E R S I O N 3 – 1 0 / 0 8



Installation

Page 16

Rig Fluids Audit


Whose permission is required prior to dumping fluids?

(m) How much dead volume is normally in the bottom of each tank?

Does it vary much from tank to tank? Yes No

Explain

Is this fluid usually removed?

Is a suction device required? Yes No

(n) Is a suction device currently stationed in the pit room? Yes No

Is it used as a matter of course? Yes No

What type is it?

Where is it situated/stored?

Is it functional? Yes No

APPENDIX 2


P A G E 4 2 V E R S I O N 3 – 1 0 / 0 8


S E C T I O N C 1

Installation

Page 17

Rig Fluids Audit


(n) continued

Suction Device

Are hoses/attachments available? Yes No

(o) If there is no such device currently available, is their space to store anduse one?

Yes No

Where?

Why is unit unavailable?

(p) Does the ditch allow fluids to be returned from the trough/flowline to thepit?

Yes No

If not, explain how these pits can be filled

Are their restrictions on operating the pit room systems? Yes No

Could it be a potential source of error/mud loss on some occasions? Yes No

(q) Is the transfer/mixing system flexible or limited? Flexible Limited

What is the potential for making errors and losing or contaminating mud?

APPENDIX 2


V E R S I O N 3 – 1 0 / 0 8



Installation

Page 18

Rig Fluids Audit

4. Pump Room

(a) Are the rig pumps bunded to prevent loss of mud? Yes No

If not, would bunding be feasible?

(b) Where are mud pump ‘pop offs’ routed to?

(c) Are the charge pumps and mud mixing pumps bunded? Yes No

(d) If mud is contained how is it recovered, or do the bunded areas allow drainage to the maindrains? Explain

(e) Do any centrifugal pumps show signs of mud leaking? Yes No

What types of seals are used?

(f) Processed Not processedIf mud enters the drains, does it then pass directlyto the sea, or is drainwater processed?e.g. by an oily water separator

Describe

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4. Pump Room (continued)

(g) If not already used, would it be possible to use a suction device toclean up any CsF/LTOBM or spills of expansion fluid?

Yes No

If not, why not?

(h) Does the installation have a history of pulsation damper failure? Yes No

If such a failure occurred, would most of the spillage be containedand recovered or lost down drains?

Yes No

Explain

5. Drill Floor

(a) What system is used for pit volume monitoring?

Does this cope with both short term/single pit losses and gains as well as being able tomonitor total changes in pit volumes i.e. can all pits be monitored while simultaneouslydetecting changes in active volumes?

Is the system used in this way? Yes No

Is it fully operational? Yes No

Is it monitored both in logging unit and on the drill floor? Yes No

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5. Drill Floor (continued)

(b) Is the pit monitoring system accurately calibrated for all pits? Yes No

If not, which pit was active and/or incorrectly calibrated?

(c) Is a suction device used for cleaning up spills? Yes No

If not, why not?

(d) Describe the drill floor drainage system, preferably using a schematic.

Is there a drill pan? Yes No

Does this collect all spillages on the floor or from a limited area?e.g. around the rotary table

Yes No

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(d) continued

Is there evidence of any malfunction in the mud collection system?e.g. drip pan leakage or insufficient collection area.

Yes No

Is there an option to return drill floor drainage to either the mud system orto the main drains?

Yes No

Describe how this system works

Is there a standard procedure? Yes No

(e) Is there a mousehole? Yes No

Is there a rathole? Yes No

Do they drain openly? Yes No

Do they drain to a mud collection tank? Yes No

Does this tank receive mud from any other points? Yes No

Is there a mud bucket? Yes No

Is there a mud bucket drain line? Yes No

Detail mud bucket sizes available

Condition of seals

Good Average Poor

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(f) Is the mud collection tank fitted with a high level alarm connected tothe Driller’s console?

Yes No

Does the alarm work? Yes No

Test it Yes No

If there is no alarm, why is it felt unnecessary?

Is there evidence of tank overflow? Yes No

Are the mud collection tank contents usually pumped back into the system, overboard orelsewhere?

Who decides?

(g) Is drainage from the pipe rack area directed to the rotary table or the outer drains?

Describe

(h) Are inside drill pipe wipers used? Yes No

What is the opinion of drilling personnel on the use of such devices?

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(i) Is a HP wash down gun used for drill floor clean up? Yes No

Is the volume of fluid used monitored? Yes No

If so, how?

If used, what preventative measures are taken to ensure little or none escapes to the sea?

(j) Is a mud saver valve installed? Yes No

How frequently is it replaced?

How frequently is it inspected?

Does a procedure cover inspection, maintenance, and replacement?

(k) When running casing, how are the joints filled with mud?

Does the method used have a control valve, which minimises mudspillage?

Yes No

Yes NoIf the mud drains to the floor by the rotary table is it all recovered by thedrip pan?

Or lost down drains and overboard? Yes No

Or periodically recovered by a vacuum device? Yes No

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(l) Yes NoIs it possible for rainwater, washdown water and detergent to bedirected into the mud system?

How can this be avoided/minimised?

(m) Yes NoAre standpipe and choke manifold valves and pipework clearlylabelled and/or colour-coded?

(n) What is your assessment of the general level of cleanliness and housekeeping on the rigfloor?

(o) What is your assessment for rig floor spillages, which cannot be recovered?

6. Trip Tank

(a) Provide a schematic or sketch of the trip tank system.

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6. Trip Tank (continued)

(b) What is the total capacity of the trip tank?

What is the effective capacity of the trip tank?

Have you verified these volumes by measurement? Yes No

(c) What is the dead volume in the bottom of the trip tank?

Can it be pumped dry or does it have to be dumped? Pump Dry Dump

If there is a dump valve? Yes No

Is it padlocked? Yes No

If not, why not?

If padlocked, where is the key?

Who is allowed to carry out the dumping?

On whose authority?

(d) Is a high level alarm fitted? Yes No

If not fitted, is one necessary? Yes No

Will the trip tank fill pump, fill the tank at a faster rate than the overflowpipe(s) can take if the pump is left running accidentally?

Yes No

Is there any evidence of trip tank overflow? Yes No

(e) Is the level monitored by electronic readout? Yes No

Is the level monitored by mechanical means e.g. float? Yes No

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6. Trip Tank (continued)

(e) continued

Is the level monitored by both of the above? Yes No

Can the level be physically seen from the Driller’s console? Yes No

(f) Yes NoDoes the Driller/Assistant Driller during every trip/casing job fill in tripsheets?

Where are records kept and for how long?

(g) Does the trip tank fill pump leak? Yes No

Has it been fitted with mechanical seals? Yes No

Is there evidence of previous leakage? Yes No

(h) Is the trip tank pump bunded? Yes No

How is contained mud recovered?

(i) Yes NoIs the tank and all associated lines and valves clearly labelled andcolour coded?

Describe deficiencies

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7. Flowline

(a) Is there any evidence of leakage from the bell nipple? Yes No

(b) Yes NoIs the flowline clear of any bends, kinks, obstructions or changes indiameter, which could result in loss of circulating fluid by cuttingsblockage?

(c) Is the flowline open to the elements allowing ingress of rainwater/run off? Yes No

(d) Is the flowline accessible for cleaning? Yes No

8. Solids Removal

Obtain schematic of system including capacity of tanks, positioning of equipment, windowsand equalisers, and flow path options available

Shale Shakers

(a) Manufacturer Type Number Condition

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8. Solids Removal (continued)

Shale Shakers (continued)

(b) Approximate capacity of header box

(c) Is there a jetting system? Yes No

(d) Are there splash plates, etc in front of shakers to prevent mud losses? Yes No

(e) Is the header box needed? Yes No

Can a false bottom be welded in to save volume? Yes No

(f) Does the gas detector inhibit flow? Yes No

(g) Is fluid distribution onto shakers satisfactory? Yes No

(h) Are gates onto shakers adjustable? Yes No

(i) Where does any overflow from header box go? Explain

(j) If the rig is equipped with riser booster pumps, can the shakers handlethe increased flow?

Yes No

(k) Itemise variable operating parameters

(l) Are any equipment operating procedures posted in the shaker house? Yes No

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(m) What form of operational training does the contractor give?

What form of operational training does the service company give?

(n) How do you rate personnel awareness of mud losses?

Good Average Poor

How do you rate personnel awareness of equipment operation?

Good Average Poor

(o) Are any equipment operation records kept? Yes No

Are these sufficiently comprehensive?

(p) What is the general condition of the units?

Good Average Poor

Are bolts seized up? Yes No

Are the bolts missing? Yes No

Can the shakers be readily jacked up and down? Yes No

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(q) Where are spares kept?

Are there sufficient items kept? Yes No

What do you recommend be kept?

Is there a spares inventory? Yes No

(r) Are their sand traps below the shakers? Yes No

How many?

What is the capacity of each?

How are they connected?

(s) Are all the shakers working efficiently? e.g. correct rpm Yes No

Linear and forward transport Yes No

If not explain

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(t) Is their adequate screen protection?

Used Yes No New Yes No

Is there adequate screen storage?

Used Yes No New Yes No

Are racks labelled according to screen size? Yes No

Are they properly used? Yes No

Is an up-to-date screen inventory in operation? Yes No

Mud Cleaner/Desilter/Desander


(b) Detail any variable operating parameters

(c) Are operating parameters posted nearby any units? Yes No

(d) Has the contractor undertaken any form of training in the operation ofthese items of equipment?

Yes No

Is any formal training undertaken in the operation of these items ofequipment by service companies?

Yes No

(e) Are any operational records kept? Yes No

Are these sufficient? Yes No

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Mud Cleaner/Desilter/Desander (continued)

(f) Are the desander cone bolts easy to undo? Yes No

Are hydrocyclone clamps easy to undo? Yes No

Give details

(g) Are inlet pressure valves fitted? Yes No

Details

(h) Yes NoIs hydrocyclone balanced when pumping water? (no more than a fewdrips from bottom)

(i) Solids Control Centrifugal Pumps - for each item of equipment onboard detail the following

Core Size Horsepower or kW Number Impeller Size RPM

(j) Can the mud cleaner be easily jacked up and down? Yes No

n/a

(k) Yes NoIs there a preventative maintenance programme in place for thereplacement of worn parts, etc?

(l) Check if the pumps are correctly sized for each item of equipment

Equipment Impeller Size Pump RPM Input Pressure Inlet Head

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Mud Cleaner/Desilter/Desander (continued)

(m) Are lines and valves colour coded? Yes No

Are lines and valves clearly identified? Yes No

Centrifuge(s), including Cuttings Cleaning Equipment and Mud Recovery System


(b) Detail any variable operating parameters e.g. feed rate, rpm, automatically variable, semi-automatic

(c) Are operating procedures posted on or near the unit? Yes No

Are they sufficiently clear and informative? Yes No

(d) Are lines and valves colour coded? Yes No

Are lines and valves clearly identified? Yes No

(e) Is any operational training provided by the contractor? Yes No

Is any operational training provided by the service company? Yes No

(f) How do you rate personnel awareness levels of the potential for mud losses occurring withthe incorrect operation of any of these items of equipment?

Good Average Poor

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Centrifuge(s), including Cuttings Cleaning Equipment and Mud Recovery System (continued)

(g) Are operational records being kept? Yes No

Are they sufficiently comprehensive? Yes No

(h) Detail tank sizes, flow path options and any other variables that are available in order tocope with varying process conditions

What are the maximum processing rates for each item of equipment?

(i) Is there a preventative maintenance programme in operations? Yes No

How do you rate on-site spares availability?

Good Average Poor

(j) Is it feasible to collect samples for solids and retention analysis? Yes No

Note Several sampling points may be required for the evaluation of cuttings and mudrecovery systems

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9. Filtration Equipment

10. Mud Laboratory

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11. Supplementary Areas

BOP Deck

(a) Is the stack and BOP deck clean? Yes No

(b) Is there any evidence of previous mud spillages? Yes No

(c) Is there evidence of the bell nipple having overflowed? Yes No

(d) Is there evidence of the mud collection tank having overflowed or leaked? Yes No

(e) Is there any evidence of other overflows or leakse.g. trip tanks being overfilled?

Yes No

(f) Is there leakage or evidence of leakage at the slip joint? Yes No

Cement Unit

(a) Are the pumps bunded in order to prevent loss to the drains and sea? Yes No

How feasible would this be if bunding is not in place?

(b) How are the cement mixing tanks and batch tank dumped and cleared of fluid?

Can fluid be sucked out using a vacuum device prior to cleaning? Yes No

Can fluid be pumped back to pits? Yes No

(c) What is the potential for fluid contamination in the line(s) from the pits to the cement unit?

Can it be avoided altogether? Yes No

Explain how

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11. Supplementary Areas (continued)

Decks

(a) What is the level of cleanliness of decks below and to the sides of the derrick package?

(b) Are the drains blocked? Yes No

(c) Are the decks dirty with fluid, indicating potential for further spillages? Yes No

(d) How do you rate the overall level of cleanliness and housekeeping?

Good Average Poor

(e) Are steps taken quickly to clean up or prevent minor spills? Yes No

Who is responsible for issuing such clean-up instructions?

Cabot Specialty Fluids Auditor

Name

Signature

Installation

Audit Date

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12. Recommended Modifications & Equipment Checks

APPENDIX 2

section c1 fluids management - cabot specialty fluids

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