Drilling problems and hydrogen sulphide safety

Marcus asks Ethan to read the daily drilling reports from the ten nearest offset wells and add up every hour that was not spent making hole or doing planned work. The total surprises him: about one day in six went to problems. 'That's normal for a field,' Marcus says, 'and that's why this lesson pays for the whole course. Nonproductive time is where wells go over budget, and where people get hurt when the crew is rushing to recover.'

Nonproductive time

Nonproductive time (NPT) is rig time lost to unplanned events: equipment failures, waiting on weather or services, and downhole problems such as stuck pipe, lost circulation, wellbore instability and well control incidents. Industry studies commonly find that downhole problems are a large share of NPT. The drilling engineer's job is to predict the likely problems from offset data, design to avoid them, and prepare responses so that, when they happen, they cost hours rather than days.

Stuck pipe

Stuck pipe is one of the costliest drilling problems. Its mechanisms fall into three groups, and the right response depends on recognizing which one is acting.

Differential sticking happens when the string lies still against a permeable formation covered with filter cake, and the overbalance pushes it into the cake. The sticking force is roughly the pressure difference times the contact area times a friction coefficient, and grows with time as the pipe embeds deeper. Its signs: the pipe becomes stuck after it has been stationary, typically during a connection or survey; circulation is still possible; the string cannot move up, down or rotate. Prevention includes keeping the overbalance low, keeping the pipe moving, using thin, slick filter cake and lubricants, and minimizing the length of collars against permeable zones. The first response is to work the pipe and apply the jar, then to spot fluids that reduce the cake friction or to reduce the hydrostatic pressure if the well allows.

Pack-off and bridging happen when solids fill the annulus around the string: cuttings beds sliding in deviated holes, cavings from unstable shale, unconsolidated sand falling in, or junk. Signs include rising pump pressure, loss of returns and difficulty moving the pipe while circulating. Wellbore geometry sticking happens when the string meets a ledge, a key seat worn into a dogleg by the rotating pipe, an undergauge hole after a worn bit, or a stiff BHA that cannot pass a crooked section. Each has its own prevention: good hole cleaning (lesson 5), mud chemistry and weight to hold shales, reaming before tripping, and controlled doglegs.

Locating and freeing stuck pipe

When pipe is stuck, the depth of the stuck point is estimated from stretch: a known pull above the string's hanging weight stretches the free pipe above the stuck point by an amount proportional to its length. This simple calculation is confirmed with a free-point tool on wireline. If the pipe cannot be freed, it is backed off or cut above the stuck point and the stuck section becomes a fish, to be recovered with fishing tools or left in place while the well is sidetracked. The decision between fishing and sidetracking is economic: fishing time is compared with the cost of a new section.

Lost circulation

Lost circulation is the loss of mud to the formation, partial or total. Mud is lost into very permeable or vuggy rock, into natural fractures, or into fractures the well itself creates when the ECD or surge pressure exceeds the fracture gradient. Losses waste expensive mud, can drop the mud level enough to cause a kick, and can damage the reservoir. Prevention means keeping ECD and surge pressures in the window, sometimes adding wellbore strengthening materials ahead of a weak zone. Treatments range from lost-circulation material pills of graded particles and fibres, to cement plugs and specialized gunk squeezes for severe losses, to drilling with managed pressure or casing off the zone.

Wellbore instability

Shales are the commonest source of instability. Mechanical instability occurs when the mud weight is too low to support the stresses around the hole, causing breakouts and large, angular cavings, or too high, causing fractures. Chemical instability arises when water from the mud enters shale, swelling clays and weakening the rock over time. The hole may enlarge or close, causing tight hole, packing off and poor cement. Remedies include choosing the mud weight from a geomechanical model, using inhibitive water-based or oil-based muds, and limiting the time the hole is left open.

# Drilling problems: differential sticking force, free point from stretch, and soft-string drag in the lateral
import math
SI = True   
if SI:
    dp_k = (1150 * 9.81 * 1560 / 1000) - 9.03 * 1560          # overbalance kPa at the heel
    dp = dp_k / 6.894757                                      # psi
    mu, contact_in, wall_ft = 0.15, 2.0, 30 / 0.3048           # friction, contact width (in), cake contact length
else:
    dp = 0.052 * 10.2 * 10450 - 0.514 * 10450
    mu, contact_in, wall_ft = 0.15, 2.0, 30.0
force = mu * dp * contact_in * wall_ft * 12                  # lbf = friction x pressure x area (in2)
print(f"overbalance {dp*6.894757:,.0f} kPa; differential sticking force over 30 m {force*0.004448:,.0f} kN" if SI
      else f"overbalance {dp:,.0f} psi; differential sticking force over 30 ft of contact {force:,.0f} lbf")
# free point from pipe stretch: L = E * A * stretch / pull
E, As = 30e6, 3.6                                            # psi, steel area of 4 in (101.6 mm) pipe in in2 (approximate)
pull, stretch_in = 40000.0, 24.0
L = E * As * stretch_in / 12 / pull
print(f"free point about {L*0.3048:,.0f} m below the rotary table" if SI else f"free point about {L:,.0f} ft below the rotary table")
# soft-string drag: weight of the lateral pipe on the low side times friction, tripping out (axial only)
w = 16.6 * (1 - (1150 / 119.826 if SI else 10.2) / 65.5)     # buoyed lb/ft
lat = 1600 / 0.3048 if SI else 9800.0
for f in (0.20, 0.25, 0.30):
    drag = f * w * lat
    print(f"  friction factor {f:.2f}: lateral drag {drag*0.004448:,.0f} kN when pulling out" if SI else f"  friction factor {f:.2f}: lateral drag {drag:,.0f} lb when pulling out")

overbalance 3,512 kPa; differential sticking force over 30 m 803 kN
free point about 1,646 m below the rotary table
  friction factor 0.20: lateral drag 66 kN when pulling out
  friction factor 0.25: lateral drag 83 kN when pulling out
  friction factor 0.30: lateral drag 99 kN when pulling out

The overbalance at the heel of the 03-22 well, with 1,150 kg/m³ mud against a depleted Cardium at about 920 kg/m³ equivalent, is about 3,500 kPa. Over 30 m of contact, the differential sticking force would be about 800 kN, close to the rig's whole hook load: a string stuck that way would almost certainly need a sidetrack. Ethan recommends reducing the lateral mud density to about 1,050 kg/m³ if the wellbore stability model allows, and keeping the pipe moving during connections. The stretch calculation shows how a pull of about 178 kN that stretches the pipe 0.61 m would place the stuck point near 1,650 m. In the lateral, friction factors from 0.20 to 0.30 add 66 to 99 kN of drag when pulling out.

Torque and drag

In deviated and horizontal wells, the string lies on the low side and touches the wall at bends, so friction adds drag when moving the pipe axially and torque when rotating it. Torque and drag models, usually the soft-string model that treats the string as a cable following the hole, calculate the hook load when tripping in and out and the surface torque, using friction factors calibrated on offset wells, typically 0.15 to 0.30 depending on mud type and casing or open hole. The models check that the rig and pipe can handle the loads, that the string will not buckle severely when pushed, and that casing can reach bottom. During drilling, measured hook loads and torque plotted against the model show developing problems: rising friction factors point to poor hole cleaning, ledges or sticking tendencies.

Hydrogen sulphide

Hydrogen sulphide (H₂S) is a colourless gas that occurs in some oil and gas reservoirs. At low concentrations it smells of rotten eggs, but it quickly paralyses the sense of smell, so odour is not a reliable warning. At high concentrations it causes collapse and death within minutes. It is heavier than air and collects in low places such as cellars and tanks. H₂S also causes sulphide stress cracking of steel (lesson 8).

In Alberta, the Occupational Health and Safety Code sets exposure limits for H₂S, with an 8-hour limit and a ceiling limit that must never be exceeded, and the the AER classifies sour wells and requires emergency response planning for them. Industry training such as H₂S Alive is required for workers on sour sites.

Sour drilling operations use fixed and personal H₂S monitors with alarms, wind indicators, briefing areas upwind, breathing air equipment and trained crews, sour-service tubulars and BOP equipment, and emergency response plans that cover the public near the site. The drilling engineer's part is to identify sour zones from offset data, specify the equipment and metallurgy, and make sure the plan includes detection, response and rescue arrangements.

Learning from the offset problems

Ethan sorts the offset nonproductive time by cause. The largest items are two stuck-pipe events in depleted intervals, several days of losses in one well where the surge pressure from running casing too fast fractured the shoe, and repeated tight hole on trips through a shale above the target that had been exposed for many days. For each, he writes a prevention measure into the program: lower mud density and pipe movement rules in depleted zones; running speed limits for casing based on surge calculations; and a requirement to minimize open-hole time through the shale, with a wiper trip only if torque and drag trends show it is needed.

He also notes the time each event took to resolve. The stuck-pipe events that were freed within an hour by jarring cost little; the two that were not freed within a day ended in sidetracks costing several days each. Marcus explains the practice of setting a decision point in advance: if pipe is not free after a set time and set number of jarring cycles, the team stops trying and moves to the next option, rather than spending days on a fishing job whose odds have become poor.

Other hazards

Shallow gas, gas trapped in shallow sands, can flow quickly and is dangerous because the shallow casing may not be strong enough to shut it in; it is usually handled by diverting the flow away from the rig rather than closing the well. Boulders and unconsolidated gravel near surface can cause lost circulation and stuck pipe in surface holes. Salt can creep and close the hole; sticky clays can ball bits; and fractured carbonates can take whole mud. The offset review lists which of these occur in the area so that each has a planned response.

Communication when problems happen

When a problem begins, the wellsite supervisor calls the drilling engineer, and the two agree on the immediate response from the program and on when to escalate. Ethan practises the call with Marcus: the current depth and operation, what was seen and when, what has been done, the current pressures and volumes, and what is proposed next. Clear, structured reports save time and prevent misunderstandings, which matter most when the crew is under pressure.