Problems Associated with Drilling Operations

Introduction

The rotary drilling rig and its components are the major vehicle of modern 

drilling activities. In this method, a downward force is applied on the drill 

bit that breaks the rock with both downward force and centrifugal force, 

thereby forming the pivotal part of an effective drilling operation. The con￾ventional practice in the oil industry is to use robust drillstring assembly 

for which large capital expenses are required. However, during any drill￾ing operation, numerous challenges are encountered, each of which can 

have significant impact on the time required to complete a drilling project. 

Often, one problem triggers another problem and snowballing of problems 

occurs, thus incapacitating the drilling process. In this process, there is no 

‘small’ or ‘large’ problem, as all problems are intricately linked to each other, 

eventually putting safety and environmental integrity in jeopardy. Any such 

impact has immeasurable financial impact beyond short-term effects on the 

‘time loss’. This chapter discusses some of the generic drilling problems, such 

as H2

S-bearing zones and shallow gas, equipment and personnel, objects 

dropped into the well, resistant beds encountered, fishing operations, 

 junk retrieve operations, and twist-off. It identifies the key areas where we 

encounter drilling problems, their root causes, and solutions related to drill￾ing methods. In well planning, the key to achieving objectives successfully 

is to design drilling programs on the basis of anticipation of potential hole 

problems rather than on caution and containment. The desired process is 

to preempt any problem, because drilling problems can be very costly after 

they occur. The most prevalent drilling problems include pipe sticking, lost 

circulation, hole deviation, pipe failures, borehole instability, mud contami￾nation, formation damage, hole cleaning, H2

S-bearing formation and shal￾low gas, and equipment and personnel-related problems.

2.1 Problems Related to Drilling 

Methods and Solutions

2.1.1 Sour Gas Bearing Zones

During drilling and workover operations, the consequences of leaks with 

sour gas or crude may be devastating. Drilling H2

S-bearing formations poses 

one of the most difficult and dangerous problems to humans and equipment. 

Personnel can be injured or even killed by relatively low concentrations of 

H2

S in a very short period of time. Equipment can experience terrible fail￾ure due to H2

S gas-induced material failure. This risk depends primarily 

on the H2

S content with the formation fluids, formation pressure, and the 

production flow rate. This information is used to assess the level of risk from 

the presence of H2

S. In addition, if this risk is known or anticipated, there 

are very specific requirements to abide by in accordance to International 

Association of Drilling Contractors (IADC) rules and regulations. All infor￾mation will ultimately lead to the requirement for special equipment, layout, 

and emergency procedures for drilling and/or workover operations.

2.1.1.1 How to Tackle H2

S

The presence of H2

S can be anticipated from previous data on the field, or 

from the region. For a wildcat, all precautionary measures should be taken, 

following IADC rules, as if H2

S will be encountered. The following steps 

and the plans should be followed while H2

S gas is encountered.

i) Planning of operations

A study should be done on geological and geographical 

information of the area. This study should include history

      of adjacent wells in order to predict the expected area where 

H2

S may be encountered. Information should be obtained 

and taken into consideration about the area and known field 

conditions, including temperatures, pressures, proposed 

well depth, and H2

S concentrations.

A mud program should be drawn up which will provide dif￾ferent pressures expected to be encountered. However, H2

scavenger should also be included to reduce the reaction of 

H2

S on the drillstring and related equipment to control the 

processing of H2

S at surface. Normal practice is to maintain 

a higher than normal pH (i.e., 10.5–11) and to treat the mud 

with a suitable scavenger as soon as dissolved sulphides are 

analyzed. The contamination of water-based muds due to 

H2

S can deteriorate the mud properties at a fast rate. It is 

advisable to keep the mud moving with immediate treat￾ment to maintain the desired properties.

Maintaining a high pH or using a scavenger is not suitable 

to safeguard drilling equipment against H2

S, since in a kick 

situation the wellbore may become partially/fully devoid 

of drilling fluid, thus reducing or eliminating the ability to 

contact drillstring and wellhead and BOP components with 

scavenger. H2

S resistant materials should be considered 

for this well control condition. The BOPs must be made to 

NACE specifications that conform to the presence of H2

S.

Prior to reaching the H2

S-bearing formations, the emergency 

equipment (blowout preventer, degasser, etc.) and response 

procedures should be tested in an exercise that simulates a kick.

Wind direction should be considered for the layout of equip￾ment such as shale shakers, choke manifold, mud tanks, and 

particularly vents such as flare lines, degasser vents, mud-gas 

separator vents, and diverter lines. Wind socks on the site or 

platform should enable identification of upwind assembly 

points. For offshore operations, each assembly point should 

allow easy evacuation from the installation.

ii) Drilling equipment selection

Equipment should be selected after consideration of metallurgical proper￾ties, thus reducing the chances of failure from H2

S-induced corrosion. The 

following recommendations are to be followed for H2

S designated wells:

a. BOP stack

Metallic materials for sour-gas service should be employed.

                                         All pressure containing components of the BOP stack with 

the potential to be exposed to H2

S should be manufactured 

with the material, which meets the standard of the NACE 

MR-01-75 and API RP 53. These components include annu￾lar preventer, rams, drilling spools, the hydraulic operated 

choke line valve, and gaskets, etc.

Non-metallic materials for sour service.

Non-metallic materials for sour service should conform to 

API RP 53, Section 9. A.8. Fluoropolymers, such as Teflon 

or Ryton and fluoroelastomers, such as viton or Kalrez are 

acceptable materials.

Welding should conform to sour-gas service.

Where welding is required for component fabrication, the 

welding and the heat affected zone of the welded compo￾nents should possess essentially the same chemical and 

physical properties as the parent metals of the subcompo￾nents. These include hardness properties and impact prop￾erties where appropriate. The welding is also required to be 

free of linear defects such as cracks, undercutting, and lack 

of fusion.

Sour-gas service identification should be performed.

Components should be marked in a manner that shows their 

suitability, under NACE MR-01-75, for sour service.

Identification stamping procedures as detailed in NACE 

MR-01-75, Section 5.4 should be followed.

Transportation, rigging up, and maintenance should con￾form to sour-gas requirements.

During transportation, rigging up, and maintenance of BOP 

stacks, operating practices should be used to avoid cold tem￾perature that might induce hardening of equipment compo￾nents. Material control for replacement parts for the BOP 

stack should have specifications and quality control equiva￾lent to the original equipment.

b. Flange, bonnet cover, bolting, and nut material

Each of these intended for H2

S use should meet require￾ments prescribed in API Specification 6A section 1.4 (14th

edition).

c. Choke manifold

Piping, flanges, valves, fittings, and discharge lines (flare 

lines) used in the composition of the choke manifold 

                  assembly should contain metals and seals in accordance 

with API RP 53.

d. Degassers/mud-gas separator

The degasser should be capable of effectively removing 

entrained gases from contaminated drilling fluid circu￾lated back to the surface. The vent outlet on the degasser 

should be extended so that the extracted gas can be routed 

to a remote area for flaring or connected into the choke flare 

line. A mud-gas separator is used to extract gas containing 

H2

S from drilling fluids. This separator should be tied into a 

vent line for burning so that it cannot release the gas into the 

atmosphere close to the rig side area.

e. Flare lines

Flare lines should be installed from the degasser, choke 

manifold, and mud-gas separator according to API RP 49. 

All flare lines should be equipped with the means for con￾stant or automatic ignition.

f. Drillpipe

Because of the direct contact of drillpipe with H2

S in the 

wellbore where various temperature and pressure conditions 

exist, the lower grades of pipe should be used so as to mini￾mize hydrogen embrittlement or sulphide stress corrosion 

cracking (SSCC). Means of control to minimize hydrogen 

embrittlement and SSCC of drillpipe can also be found in 

API RP 49. Consideration may be given to the use of a drill￾string equipped with special tool joint material.

g. Monitoring equipment

Each drilling rig operating in an area known or suspected to 

produce H2

S gas should have adequate H2

S monitoring and/or 

detection equipment. It is recommended that this equipment 

should be installed 350 meters and/or one week prior to drilling 

into the H2

S zone. H2

S concentrations should be continuously 

monitored at strategic sampling positions, e.g., shale shaker, 

mud ditch, mud tank area, etc., and results transmitted both to 

the driller’s console and to the toolpusher’s office. Audible and 

visible alarms should indicate both locally and remotely when 

H2

S concentration reaches 10 ppm. Sulphide tests should be 

carried out as part of the mud testing program in areas where 

hydrogen sulphide gas (H2

S) might be encountered.

                           Mud logging unit

The mud logging unit and equipment should be located 

away from the shaker tank and a minimum of 50 meters dis￾tance should be kept from the well head.

i. Venting system

Weatherized rigs equipped with partitions permanent in 

nature should be provided with a ventilation system suffi￾cient for the removal of accumulated H2

S.

iii) Training

When drilling in an area where H2

S gas might be encountered, training of 

personnel must be carried out on the subject matter. The action should be 

taken in the event of alarm, the use of safety equipment, and escape proce￾dures whatever the likelihood of encountering H2

S. Emergency procedures 

must be practiced regularly, using realistic emergency drills.

iv) H2

S contingency planning

A contingency plan should be drawn up when H2

S is anticipated while 

drilling. The contingency plan should be developed prior to the com￾mencement of drilling operations and should include the following:

Information on the physical effects or exposure to H2

S and 

sulphur dioxide (SO2

).

Safety and training procedures should be followed and safety 

equipment will be used.

Procedures for operations when the following conditions 

exist:

pre-alarm condition

moderate danger to life

extreme danger to life

Responsibilities and duties of personnel for each operating 

condition.

Briefing areas or locations for assembly of personnel during 

extreme danger condition should be designated. At least two 

briefing areas should be established on each drilling facility. 

Of these two areas, the one upwind at any given time is the 

safe briefing area.

Evacuation plan should be in place and well rehearsed.

Plan must be in place as to who would notify the authority 

and at what stage of the incident.

    A list of emergency medical facilities, including locations 

and/or addresses and telephone numbers must be in place.

In a pre-spud meeting, the company drilling supervisor 

should review the drilling program with the drilling contrac￾tor and service contractors, outlining each party’s responsi￾bility in drilling a well, where H2

S may be encountered.

All personnel should be fully trained and the H2

S-related 

equipment should be in place when drilling at 350 meters 

above and/or one week prior to encountering a hydrogen 

sulphide zone.

Available literature should be carefully studied before draw￾ing up H2

S procedures. Recommended references are: API 

RP49 “Safe Drilling of Wells Containing Hydrogen Sulphide.”

2.1.2 Shallow Gas-Bearing Zones

Shallow gas-bearing zone is defined as any hydrocarbon-bearing zone, 

which may be encountered at a depth close to the surface or mudline. In 

generally, it is not possible to close in and contain a gas influx from a shal￾low zone because weak formation integrity may lead to breakdown and 

broaching to surface and/or mudline. This situation is particularly hazard￾ous when drilling operations continue from a fixed installation or jack￾up rig. Shallow gas-bearing zones are usually in a pressured condition. 

However, the effective increase in pore pressure due to gas gradient can 

lead to underbalance when a shallow gas zone is first penetrated.

Shallow gas may be encountered at any time in any region of the world. 

The only way to control this problem is that we should never shut in the 

well. It is also needed to divert the gas flow through a diverter system at 

the BOP. High-pressure shallow gas can be encountered at depths as low 

as a few hundred feet where the formation-fracture gradient is very low. 

The danger is that if the well is in shut-in condition, formation fracturing 

is more likely to occur. This will result in the most severe blowout problem, 

and ultimately an underground blow.

The identification and avoidance of shallow gas will be a principal objec￾tive in well planning and site survey procedures. All drilling programs shall 

contain a clear statement on the probability and risk of encountering shal￾low gas. This will be based on seismic survey and interpretation together 

with offset geological and drilling data. For onshore operations, consid￾eration should be given for carrying out shallow seismic surveys in areas 

of shallow gas risk. In the absence of such surveys, assessment should be 

based on the exploration seismic data, historical well data, and the geo￾logical probability of a shallow gas trap. If shallow 

gas is a likelihood at 

                            

the proposed drilling location, a shallow gas plan specific to company 

and the drilling contractor must be prepared prior to spudding the well. 

Special consideration should be given to: crew positions, training, evacu￾ation plan, and emergency power shut down. For offshore operations, the 

presence of shallow gas can be extremely hazardous especially if no spe￾cific plan of action is prepared prior to spudding of the well. The driller 

will be instructed in writing on what action should be taken if a well kick 

should be noticed while drilling. The problem of drilling a shallow hole is 

that normal indications of a kick are not reliable. For example, penetration 

rates vary tremendously, and mud volume is continuously being added to 

the active system. The most reliable indicator is the differential flow sen￾sor. Due to the difficulties of early detection and the depth of shallow gas 

reservoirs, reaction time is minimal. In such case, extreme caution, and 

alertness are required.

2.1.2.1 Prediction of Shallow Gas Zone

Although the location of gas pockets is difficult to predict, high-resolution 

seismic data acquisition, processing and interpretation techniques increase 

the reliability of the shallow gas prognosis. Therefore, surveys are to be 

recommended. Well proposals should always include a statement on the 

probability of encountering shallow gas, even if no shallow gas is pres￾ent. This statement should not only use the “shallow gas survey”, but also 

include an assessment drawn from the exploration seismic data, historical 

well data, the geological probability of a shallow cap rock, coal formations, 

and any surface indications/seepages. The shallow gas procedures based 

on the shallow gas statement in the well proposal, and practical shallow 

gas procedures should be prepared for that particular well. The following 

guidelines should be adhered to avoid influx and kick: i) avoid shallow 

gas where possible; ii) optimize the preliminary shallow gas investigation; 

iii) the concept of drilling small pilot holes for shallow gas investigation 

with a dedicated unit is considered an acceptable and reliable method of 

shallow gas detection and major problem prevention; iv) surface diverter 

equipment is not yet designed to withstand an erosive shallow gas flow for 

a prolonged period of time. Surface diverters are still seen as a means of 

“buying time” in order to evacuate the drilling site; v) diverting shallow 

gas in subsea is considered to be safer as compared to diverting at surface, 

vi) dynamic kill attempt with existing rig equipment may only be success￾ful if a small pilot hole (e.g., 9 7/8” or smaller) is drilled and immediate 

pumping at maximum rate is applied in the early stage of a kick; and vii) 

riserless top hole drilling in floating drilling operations is an acceptable 

and safe method.

                     Identification of Shallow Gas Pockets

While drilling at shallow depth in a normally pressured formation, no 

indication of a gas pocket can be expected other than higher gas readings 

in the mud returns. Since the overbalance of the drilling fluid at shallow 

depths is usually minimal, pressure surges may cause an underbalanced 

situation which could result in a kick. Therefore, every attempt should be 

made to avoid swabbing. Some definitions are used to describe the risk 

in shallow gas assessment, such as i) high: an anomaly showing all of the 

seismic characteristics of a shallow gas anomaly, that ties to gas in an offset 

well, or is located at a known regional shallow gas horizon, ii) moderate: 

an anomaly showing most of the seismic characteristics of a shallow gas 

anomaly, but which could be interpreted not to be gas and, as such rea￾sonable doubt exists for the presence of gas, iii) low: an anomaly showing 

some of the seismic characteristics of a shallow gas anomaly, but that is 

interpreted not to be gas although some interpretative doubt exists, and 

iv) negligible: either there is no anomaly present at the location or anomaly 

is clearly due to other, nongaseous, causes.

There are two factors that make shallow gas drilling a difficult challenge. 

First, unexpected pressure at the top of the gas-bearing zone, most often 

due to the “gas effect” dictated by zone thickness and/or natural dip, can 

be significant. This pressure is usually unknown, seismic surveys being 

often unable to give an idea either about thickness or in-situ gas concen￾tration. In more complex situations, deep gas may migrate upwards along 

faults. For example, the influx in Sumatra could not be stopped even with 

10.8 ppg mud at very shallow depth because the bit had crossed a fault 

plane. Second, low formation fracture gradients are a predominant factor 

in shallow gas operations.

These two factors result in reduced safety margin for the driller. Minor 

hydrostatic head loss (e.g., swabbing, incorrect hole filling, cement slurry 

without gas-blocking agent), any error in mud weight planning (e.g., gas 

effect not allowed for), or any uncontrolled rate of penetration with sub￾sequent annulus overloading will systematically and quickly result in well 

bore unloading. Shallow gas flows are extremely fast-developing events. 

There is a short transition time between influx detection and well unload￾ing, resulting in much less time for driller reaction and less room for 

error. Poor quality and reliability of most kick-detection sensors worsen 

problems.

Previous history has disclosed the magnitude of severe dynamic loads 

applied to surface diverting equipment, and consequent high probability of 

failure. One of the associated effects is erosion, which leads to high poten￾tial of fire hazards and explosion from flow impingement on rig facilities.

The risk of cratering is a major threat against the stability of bottom￾supported units. As it is impossible to eliminate them (i.e., most shallow 

gas-prone areas are developed from bottom supported units), emphasis 

should be put on careful planning and close monitoring during execution.

2.1.2.3 Case Study

Description: Four new wells were drilled at an offshore platform with cas￾ing on the surface section in batch-drilling mode. 13⅜-in casing shoes 

were set as per plan in a range from 1,800 to 2,000 ft for the four wells 

(Figure 2.1). All the risk-control measures resulting from the risk-analysis 

exercise were implemented when drilling the section. In the first well, 

logging-while-drilling tools were included in the bottomhole assemblies 

(BHA). There were no indications of a shallow gas zone.

Drilling Plan: The plan was to use seawater for the four wells because the 

drilling fluid was for the casing-drilling operation.

Drilling Operations and Potential Problems: Pumping sweeps were 

performed at every connection to help with hole cleaning. Following the 

plans, the first of the four wells was drilled with seawater and sweeps. Soon 

after drilling out of the conductor, fluid losses were experienced.

First Aid Remedy and Consequences: Loss-control material was pumped 

downhole and drilling continued, expecting the coating effect to contribute 

in building a mudcake that would eventually cease the losses. Drilling-fluid 

      

losses decreased but did not stop until section total depth (TD) was reached

and casing was cemented. In addition, when drilling the first well, accurate

position surveys were taken, which required several attempts at every sur￾vey station. These attempts were due to the poor data transmission from

measurement-while-drilling (MWD) tools. The result was an increase of

10% non-productive (e.g., off-bottom) drilling time compared with other

wells. The problems with the MWD transmission also affected the resistiv￾ity and gamma ray data that were planned to provide early information of

any shallow gas accumulation. As a result, it was difficult to interpret the

real-time data provided by the logging tool.

Final Solution: The engineering team decided to change the drilling fluid

from seawater to a low-viscosity mud. They were expecting to build a better

mudcake and to improve fluid-loss control. To improve the MWD transmis￾sion, a low telemetry rate was set on the tools to reduce the time required to

take a survey. These measures contributed to drill the next three wells with

no drilling-fluid losses and with no delays from a lengthy survey procedure.

Lesson Learned: The seawater-and-sweeps system was replaced with a low

viscosity water-based-mud drilling fluid after the problems that had been

faced in the first well. As a result, the three remaining wells were drilled

with improved drilling practices. Severe fluid losses were not observed, and

the quality of the telemetry signal improved substantially. A possible expla￾nation for the problems with the use of seawater are: i) drilling fluid does

not have the required properties to create a consistent mudcake around

the wellbore wall, ii) the use of seawater also induced turbulent flow, which

may give good hole cleaning but would increase the hole washouts in shal￾low formations. An enlarged wellbore and the inability to create an opti￾mum mudcake might have eliminated the coating effect and the expected

improvements in terms of loss control. Problems with the telemetry-signal

quality were attributed to the telemetry rate setup and the noise created by

the drilling fluid. Setting a low telemetry rate in the MWD proved useful

for adapting to the particular condition of casing drilling, where the inter￾nal diameter in the drillstring experiences great variations, such as 2.8 in.

at the BHA and 12.6 in. for the rest of the string.

Personal Experiences: The following are the field experience for diverter

procedures while drilling a top hole. At first sign of flow,

1. Do not stop pumping.

2. Open diverter line to divert/close diverter (both functions

should be interlocked).
                        

            Increase pump strokes to a maximum limit (DO NOT 

exceed maximum pump speed recommended by the manu￾facturer or maximum pressure allowed by relief valve).

4. Switch suction on mud pumps to heavy mud in the reserve 

pit. Zero stroke counter.

5. Raise alarm and announce emergency using the PA system 

and/or inform the rig superintendent. Engage personnel to 

look for gas (Jack-up).

6. If the well appears to have stopped flowing after the heavy 

mud has been displaced stop pumps and observe well.

7. If the well appears to continue to flow after the heavy mud 

has been pumped, carry on pumping from the active system 

and prepare water in a pit for pumping and/or consider pre￾paring pit with heavier mud. When all mud has been con￾sumed, switch pumps to water. Do not stop pumping for as 

long as the well continues to flow.

General Guidelines for Drilling Shallow Gas: The following guidelines 

shall be adhered to while drilling:

Consideration shall be given to drilling a pilot hole with the 

8 ½” or smaller bit size when drilling explorations wells. The 

BHA design shall include a float valve and considerations 

should be given to deviation and subsequent hole opening. 

The major advantages of a small pilot hole are: i) the Rate of 

Penetration (ROP) will be controlled to avoid overloading 

the annulus with cuttings and inducing losses, ii) all losses 

shall be cured prior to drilling ahead. Drilling blind or 

with losses requires the approval from head of operations, 

iii) pump pressure shall be closely monitored and all con￾nections (on jack-up) shall be flow checked, iv) pipe shall be 

pumped out of hole at a moderate rate to prevent swabbing.

General Recommended Drilling Practices in Shallow Gas Areas: 

Common drilling practices, which are applicable for top hole drill￾ing in general and diverter drilling in particular are summarized below. 

Recommendations are made with a view to simplify operations, thereby 

minimizing possible hole problems.

A pilot hole should be drilled in areas with possible shallow 

gas, because the small hole size will facilitate a dynamic well 

killing operation.

      The penetration rate should be restricted. Care should be 

taken to avoid an excessive build-up of solids in the hole that 

can cause formation breakdown and mud losses. Drilling 

with heavier mud returns could also obscure indications of 

drilling through higher pressured formations. The well may 

kick while circulating the hole cleaning. Restricted drilling 

rates also minimize the penetration into the gas-bearing for￾mation which in turn minimizes the influx rate. An excessive 

drilling rate through a formation containing gas reduces the 

hydrostatic head of the drilling fluid, which may eventually 

result in a flowing well.

Every effort should be made to minimize the possibility of 

swabbing. Pumping out of the hole at optimum circulating 

rates is recommended for all upward pipe movements (e.g., 

making connections and tripping). Especially in larger hole 

sizes (i.e., larger than 12”), it is important to check that the 

circulation rate is sufficiently high and the pulling speed is 

sufficiently low to ensure that no swabbing will take place. 

A top drive system will facilitate efficient pumping out of 

hole operations. The use of stabilizers will also increase the 

risk of swabbing; hence the minimum required number of 

stabilizers should be used.

Accurate measurement and control of drilling fluid is most 

important in order to detect gas as early as possible. Properly 

calibrated and functioning gas detection equipment and a 

differential flowmeter are essential in top hole drilling. Flow 

checks are to be made before tripping. At any time, a sharp 

penetration rate may increase or tank level anomaly may be 

observed. When any anomaly appears on the MWD log, it 

is recommended to flow check each connection while drill￾ing the pilot hole in potential shallow gas areas. Measuring 

mud weight in and out, and checking for seepage losses are 

all important practices which shall be applied continuously.

A float valve must be installed in all BHAs which are used 

in top hole drilling in order to prevent uncontrollable flow 

up the drillstring. The float valve is the only down-hole 

mechanical barrier available. The use of two float valves in 

the BHA may be considered in potential shallow gas areas.

Large bit nozzles or no nozzles and large mud pump liners 

should be used to allow lost circulation material (LCM) to be 

pumped through the bit in case of losses. Large nozzles are 

                                    also advantageous during dynamic killing operations, since 

a higher pump rate can be achieved. For example, a pump 

rate of approximately 2,700 l/min at 20,000 kPa pump pres￾sure can be obtained using a 1300–1600 HP pump with 3 

14/32” nozzles installed in the bit. By using 3 18/32” noz￾zles, the pump rate can be increased to around 3,800 ltr/min 

at 20,000 kPa. The use of centre nozzle bits will increase the 

maximum circulation rate even further and also reduces the 

chance of bit balling.

Shallow kick-offs should be avoided in areas with prob￾able shallow gas. Top hole drilling operations in these areas 

should be simple and quick to minimize possible hole prob￾lems. BHAs used for kick-off operations also have flow 

restrictions which will reduce the maximum possible flow 

through the drillstring considerably. A successful dynamic 

well killing operation will then become very unlikely

                                                      

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