PEH II - Drilling Problems and Solutions PDF

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SHORTMAN UTT

Chapter 10 Drilling Problems and Solutions J.J. Azar, U. of Tulsa 10.1 Introduction It is almost certain that problems will occur while drilling a well, even in very carefully planned wells. For example, in areas in which similar drilling practices are used, hole problems may have been reported where no such problems existed previously because formations are nonhomogeneous. Therefore, two wells near each other may have totally different geological conditions. 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. Drilling problems can be very costly. The most prevalent drilling problems include pipe sticking, lost circulation, hole deviation, pipe failures, borehole instability, mud contamination, formation damage, hole cleaning, H2S-bearing formation and shallow gas, and equipment and personnel-related problems. Understanding and anticipating drilling problems, understanding their causes, and planning solutions are necessary for overall-well-cost control and for successfully reaching the target zone. This chapter addresses these problems, possible solutions, and, in some cases, preventive measures. 10.2 Pipe Sticking During drilling operations, a pipe is considered stuck if it cannot be freed and pulled out of the hole without damaging the pipe and without exceeding the drilling rig’s maximum allowed hook load. Differential pressure pipe sticking and mechanical pipe sticking are addressed in this section. 10.2.1 Differential-Pressure Pipe Sticking. Differential-pressure pipe sticking occurs when a portion of the drillstring becomes embedded in a mudcake (an impermeable film of fine solids) that forms on the wall of a permeable formation during drilling. If the mud pressure, pm, which acts on the outside wall of the pipe, is greater than the formation-fluid pressure, pff, which generally is the case (with the exception of underbalanced drilling), then the pipe is said to be differentially stuck (see Fig. 10.1). The differential pressure acting on the portion of the drillpipe that is embedded in the mudcake can be expressed as

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Fig. 10.1—Differential-pressure sticking.

Δ p = pm − p ff .............................................................. (10.1) The pull force, Fp, required to free the stuck pipe is a function of the differential pressure, Δp; the coefficient of friction, f; and the area of contact, Ac, between the pipe and mudcake surfaces. Fp = f Δ p A c............................................................... (10.2) From Ref. 1, A c = 2Lep {( D h / 2 − hmc) 2 − D h / 2 − hmc( D h − hmc) / ( D h − D op) 2}0.5, .............. (10.3) where D op ≤ ( D h − hmc) ........................................................... (10.4) In this formula, Lep is the length of the permeable zone, Dop is the outside diameter of the pipe, Dh is the diameter of the hole, and hmc is the mudcake thickness. The dimensionless coefficient of friction, f, can vary from less than 0.04 for oil-based mud to as much as 0.35 for weighted water-based mud with no added lubricants. Eqs. 10.2 and 10.3 show controllable parameters that will cause higher pipe-sticking force and the potential inability of freeing the stuck pipe. These parameters are unnecessarily high differential pressure, thick mudcake (high continuous fluid loss to formation), low-lubricity mudcake (high coefficient of friction), and excessive embedded pipe length in mudcake (delay of time in freeing operations). Although hole and pipe diameters and hole angle play a role in the pipe-sticking force, they are uncontrollable variables once they are selected to meet well design objectives. However,

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the shape of drill collars, such as square, or the use of drill collars with spiral grooves and external-upset tool joints can minimize the sticking force. Some of the indicators of differential-pressure-stuck pipe while drilling permeable zones or known depleted-pressure zones are an increase in torque and drag; an inability to reciprocate the drillstring and, in some cases, to rotate it; and uninterrupted drilling-fluid circulation. Differential-pressure pipe sticking can be prevented or its occurrence mitigated if some or all of the following precautions are taken: • Maintain the lowest continuous fluid loss adhering to the project economic objectives. • Maintain the lowest level of drilled solids in the mud system, or, if economical, remove all drilled solids. • Use the lowest differential pressure with allowance for swab and surge pressures during tripping operations. • Select a mud system that will yield smooth mudcake (low coefficient of friction). • Maintain drillstring rotation at all times, if possible. Differential-pressure-pipe-sticking problems may not be totally prevented. If sticking does occur, common field practices for freeing the stuck pipe include mud-hydrostatic-pressure reduction in the annulus, oil spotting around the stuck portion of the drillstring, and washing over the stuck pipe. Some of the methods used to reduce the hydrostatic pressure in the annulus include reducing mud weight by dilution, reducing mud weight by gasifying with nitrogen, and placing a packer in the hole above the stuck point. 10.2.2 Mechanical Pipe Sticking. The causes of mechanical pipe sticking are inadequate removal of drilled cuttings from the annulus; borehole instabilities, such as hole caving, sloughing, or collapse; plastic shale or salt sections squeezing (creeping); and key seating. Drilled Cuttings. Excessive drilled-cuttings accumulation in the annular space caused by improper cleaning of the hole can cause mechanical pipe sticking, particularly in directional-well drilling. The settling of a large amount of suspended cuttings to the bottom when the pump is shut down or the downward sliding of a stationary-formed cuttings bed on the low side of a directional well can pack a bottomhole assembly (BHA), which causes pipe sticking. In directional-well drilling, a stationary cuttings bed may form on the low side of the borehole (see Fig. 10.2). If this condition exists while tripping out, it is very likely that pipe sticking will occur. This is why it is a common field practice to circulate bottom up several times with the drill bit off bottom to flush out any cuttings bed that may be present before making a trip. Increases in torque/drag and sometimes in circulating drillpipe pressure are indications of large accumulations of cuttings in the annulus and of potential pipe-sticking problems. Borehole Instability. This topic is addressed in Sec. 10.6; however, it is important to mention briefly the pipe-sticking issues associated with the borehole-instability problems. The most troublesome issue is that of drilling shale. Depending on mud composition and mud weight, shale can slough in or plastically flow inward, which causes mechanical pipe sticking. In all formation types, the use of a mud that is too low in weight can lead to the collapse of the hole, which can cause mechanical pipe sticking. Also, when drilling through salt that exhibits plastic behavior under overburden pressure, if mud weight is not high enough, the salt has the tendency of flowing inward, which causes mechanical pipe sticking. Indications of a potential pipe-sticking problem caused by borehole instability are a rise in circulating drillpipe pressure, an increase in torque, and, in some cases, no fluid return to surface. Fig. 10.3 illustrates pipe sticking caused by wellbore instability. Key Seating. Key seating is a major cause of mechanical pipe sticking. The mechanics of key seating involve wearing a small hole (groove) into the side of a full-gauge hole. This groove is caused by the drillstring rotation with side force acting on it. Fig. 10.4 illustrates pipe sticking caused by key seating. This condition is created either in doglegs or in undetect-

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Fig. 10.2—Mechanical pipe sticking caused by drilled cuttings: (a) cuttings bed during drilling, and (b) cuttings jamming the drill bit during tripping out.

ed ledges near washouts. The lateral force that tends to push the pipe against the wall, which causes mechanical erosion and thus creates a key seat, is given by Fl = T sin θ dl , ............................................................. (10.5) where Fl is the lateral force, T is the tension in the drillstring just above the key-seat area, and θdl is the abrupt change in hole angle (commonly referred to as dogleg angle). Generally, long bit runs can cause key seats; therefore, it is common practice to make wiper trips. Also, the use of stiffer BHAs tends to minimize severe dogleg occurrences. During tripping out of hole, a key-seat pipe-sticking problem is indicated when several stands of pipe have been pulled out, and then, all of a sudden, the pipe is stuck. Freeing mechanically stuck pipe can be undertaken in a number of ways, depending on what caused the sticking. For example, if cuttings accumulation or hole sloughing is the suspected cause, then rotating and reciprocating the drillstring and increasing flow rate without

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Fig. 10.3—Pipe sticking caused by wellbore instability.

exceeding the maximum allowed equivalent circulating density (ECD) is a possible remedy for freeing the pipe. If hole narrowing as a result of plastic shale is the cause, then an increase in mud weight may free the pipe. If hole narrowing as a result of salt is the cause, then circulating fresh water can free the pipe. If the pipe is stuck in a key-seat area, the most likely successful solution is backing off below the key seat and going back into the hole with an opener to drill out the key section. This will lead to a fishing operation to retrieve the fish. The decision on how long to continue attempting to free stuck pipe vs. back off, plug back, and then sidetrack is an economic issue that generally is addressed by the operating company. 10.3 Loss of Circulation 10.3.1 Definition. Lost circulation is defined as the uncontrolled flow of whole mud into a formation, sometimes referred to as thief zone. Fig. 10.5 shows partial and total lost-circulation zones. In partial lost circulation, mud continues to flow to surface with some loss to the formation. Total lost circulation, however, occurs when all the mud flows into a formation with no return to surface. If drilling continues during total lost circulation, it is referred to as blind drilling. This is not a common practice in the field unless the formation above the thief zone is mechanically stable, there is no production, and the fluid is clear water. Blind drilling also may continue if it is economically feasible and safe. 10.3.2 Lost-Circulation Zones and Causes. Formations that are inherently fractured, cavernous, or have high permeability are potential zones of lost circulation. In addition, under certain improper drilling conditions, induced fractures can become potential zones of lost circulation. The major causes of induced fractures are excessive downhole pressures and setting intermediate casing, especially in the transition zone, too high. Induced or inherent fractures may be horizontal at shallow depth or vertical at depths greater than approximately 2,500 ft. Excessive wellbore pressures are caused by high flow rates

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Fig. 10.4—Pipe sticking caused by key seat.

(high annular-friction pressure loss) or tripping in too fast (high surge pressure), which can lead to mud ECD. In addition, improper annular hole cleaning, excessive mud weight, or shutting in a well in high-pressure shallow gas can induce fractures, which can cause lost circulation. Eqs. 10.6 and 10.7 show the conditions that must be maintained to avoid fracturing the formation during drilling and tripping in, respectively. λeq = λmh + Δλaf < λfrac, ..................................................... (10.6) and

λeq = λmh + Δλ s < λfrac, ................................................ (10.7)

where λmh = static mud weight, Δλaf = additional mud weight caused by friction pressure loss in annulus, Δλs = additional mud caused by surge pressure, λfrac = formation-pressure fracture gradient in equivalent mud weight, and λeq = equivalent circulating density of mud. Cavernous formations are often limestones with large caverns. This type of lost circulation is quick, total, and the most difficult to seal. High-permeability formations that are potential lostcirculation zones are those of shallow sand with permeability in excess of 10 darcies. Generally, deep sand has low permeability and presents no loss-of-circulation problems. In noncavernous thief zones, mud level in mud tanks decreases gradually and, if drilling continues, total loss of circulation may occur. 10.3.3 Prevention of Lost Circulation. The complete prevention of lost circulation is impossible because some formations, such as inherently fractured, cavernous, or high-permeability zones, are not avoidable if the target zone is to be reached. However, limiting circulation loss is possible if certain precautions are taken, especially those related to induced fractures. These precautions include maintaining proper mud weight, minimizing annular-friction pressure losses

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Fig. 10.5—Lost-circulation zones.

during drilling and tripping in, adequate hole cleaning, avoiding restrictions in the annular space, setting casing to protect upper weaker formations within a transition zone, and updating formation pore pressure and fracture gradients for better accuracy with log and drilling data. If lost-circulation zones are anticipated, preventive measures should be taken by treating the mud with lost-circulation materials (LCMs). 10.3.4 Remedial Measures. When lost circulation occurs, sealing the zone is necessary unless the geological conditions allow blind drilling, which is unlikely in most cases. The common LCMs that generally are mixed with the mud to seal loss zones may be grouped as fibrous, flaked, granular, and a combination of fibrous, flaked, and granular materials. These materials are available in course, medium, and fine grades for an attempt to seal lowto-moderate lost-circulation zones. In the case of severe lost circulations, the use of various plugs to seal the zone becomes mandatory. It is important, however, to know the location of the lost-circulation zone before setting a plug. Various types of plugs used throughout the industry include bentonite/diesel-oil squeeze, cement/bentonite/diesel-oil squeeze, cement, and barite. Squeeze refers to forcing fluid into the lost-circulation zone. 10.4 Hole Deviation 10.4.1 Definition. Hole deviation is the unintentional departure of the drill bit from a preselected borehole trajectory. Whether drilling a straight or curved-hole section, the tendency of the bit to walk away from the desired path can lead to higher drilling costs and lease-boundary legal problems. Fig. 10.6 provides examples of hole deviations. 10.4.2 Causes. It is not exactly known what causes a drill bit to deviate from its intended path. It is, however, generally agreed that one or a combination of several of the following factors may be responsible for the deviation: • Heterogeneous nature of formation and dip angle. • Drillstring characteristics, specifically the BHA makeup. • Stabilizers (location, number, and clearances).

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Fig. 10.6—Example of hole deviations.

• Applied weight on bit (WOB). • Hole-inclination angle from vertical. • Drill-bit type and its basic mechanical design. • Hydraulics at the bit. • Improper hole cleaning. It is known that some resultant force acting on a drill bit causes hole deviation to occur. The mechanics of this resultant force is complex and is governed mainly by the mechanics of the BHA, rock/bit interaction, bit operating conditions, and, to some lesser extent, by the drillingfluid hydraulics. The forces imparted to the drill bit because of the BHA are directly related to the makeup of the BHA (i.e., stiffness, stabilizers, and reamers). The BHA is a flexible, elastic structural member that can buckle under compressive loads. The buckled shape of a given designed BHA depends on the amount of applied WOB. The significance of the BHA buckling is that it causes the axis of the drill bit to misalign with the axis of the intended hole path, thus causing the deviation. Pipe stiffness and length and the number of stabilizers (their location and clearances from the wall of the wellbore) are two major parameters that govern BHA buckling behavior. Actions that can minimize the buckling tendency of the BHA include reducing WOB and using stabilizers with outside diameters that are almost in gauge with the wall of the borehole. The contribution of the rock/bit interaction to bit deviating forces is governed by rock properties (cohesive strength, bedding or dip angle, internal friction angle); drill-bit design features (tooth angle, bit size, bit type, bit offset in case of roller-cone bits, teeth location and number, bit profile, bit hydraulic features); and drilling parameters (tooth penetration into the rock and its cutting mechanism). The mechanics of rock/bit interaction is a very complex subject and is the least understood in regard to hole-deviation problems. Fortunately, the advent of downhole measurement-while-drilling tools that allow monitoring the advance of the drill bit along the desired path makes our lack of understanding of the mechanics of hole deviation more acceptable. 10.5 Drillpipe Failures Drillpipe failures can be put into one of the following categories: twistoff caused by excessive torque; parting because of excessive tension; burst or collapse because of excessive internal pressure or external pressure, respectively; or fatigue as a result of mechanical cyclic loads with or without corrosion.

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10.5.1 Twistoff. Pipe failure as a result of twistoff occurs when the induced shearing stress caused by high torque exceeds the pipe-material ultimate shear stress. In vertical-well drilling, excessive torques are not generally encountered under normal drilling practices. In directional and extended-reach drilling, however, torques in excess of 80,000 lbf-ft are common and easily can cause twistoff to improperly selected drillstring components. 10.5.2 Parting. Pipe-parting failure occurs when the induced tensile stress exceeds the pipematerial ultimate tensile stress. This condition may arise when pipe sticking occurs, and an overpull is applied in addition to the effective weight of suspended pipe in the hole above the stuck point. 10.5.3 Collapse and Burst. Pipe failure as a result of collapse or burst is rare; however, under extreme conditions of high mud weight and complete loss of circulation, pipe burst may occur. 10.5.4 Fatigue. Fatigue is a dynamic phenomenon that may be defined as the initiation of microcracks and their propagation into macrocracks as a result of repeated applications of stresses. It is a process of localized progressive structural fractures in material under the action of dynamic stresses. It is well established that a structural member that may not fail under a single application of static load may very easily fail under the same load if it is applied repeatedly. Failure under cyclic (repeated) loads is called fatigue failure. Drillstring fatigue failure is the most common and costly type of failure in oil/gas and geothermal drilling operations. The combined action of cyclic stresses and corrosion can shorten the life expectancy of ...