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PEH:Drilling Problems and Solutions
Petroleum Engineering Handbook
Larry W. Lake, Editor-in-Chief
Volume II - Drilling Engineering
Robert F. Mitchell, Editor
Copyright 2006, Society of Petroleum Engineers
Chapter 10 - Drilling Problems and Solutions
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.
- 1 Pipe Sticking
- 2 Loss of Circulation
- 3 Hole Deviation
- 4 Drillpipe Failures
- 5 Borehole Instability
- 6 Mud Contamination
- 7 Producing Formation Damage
- 8 Hole Cleaning
- 9 Hydrogen-Sulfide-Bearing Zones and Shallow Gas
- 10 Equipment and Personnel-Related Problems
- 11 Nomenclature
- 12 References
- 13 General References
- 14 SI Metric Conversion Factors
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.
Differential-Pressure Pipe StickingDifferential-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
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.
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, 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.
Mechanical Pipe StickingThe 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 undetected 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
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 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.
Loss of Circulation
DefinitionLost 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.
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 (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.
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 lost-circulation 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.
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 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).
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 low-to-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.
DefinitionHole 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.
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).
- 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 drilling-fluid 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.
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.
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.
Pipe-parting failure occurs when the induced tensile stress exceeds the pipe-material 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.
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.
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 a drillpipe by thousand folds. Cyclic stresses are induced by dynamic loads caused by drillstring vibrations and bending-load reversals in curved sections of hole and doglegs caused by rotation. Pipe corrosion occurs during the presence of O2, CO2, chlorides, and/or H2S. H2S is the most severely corrosive element to steel pipe, and it is deadly to humans. Regardless of what may have caused pipe failure, the cost of fishing operations and the sometimes unsuccessful attempts to retrieve the fish out of the hole can lead to the loss of millions of dollars in rig downtime, loss of expensive tools downhole, or abandonment of the already-drilled section below the fish.
In spite of the vast amount of work that has been dedicated to pipe fatigue failure, it is still the least understood. This lack of understanding is attributed to the wide variations of statistical data in determining type of service and environment of the drillstring, magnitude of operating loads and frequency of occurrence (load history), accuracy of methods in determining the stresses, quality control during manufacturing, and the applicability of material fatigue data.
Although pipe failure cannot be eliminated totally, there are certain measures that can be taken to minimize it. Fatigue failures can be mitigated by minimizing induced cyclic stresses and insuring a noncorrosive environment during the drilling operations. Cyclic stresses can be minimized by controlling dogleg severity and drillstring vibrations. Corrosion can be mitigated by corrosive scavengers and controlling the mud pH in the presence of H2S. The proper handling and inspection of the drillstring on a routine basis are the best measures to prevent failures.
Definition and Causes
Borehole instability is the undesirable condition of an openhole interval that does not maintain its gauge size and shape and/or its structural integrity. The causes can be grouped into the following categories: mechanical failure caused by in-situ stresses, erosion caused by fluid circulation, and chemical caused by interaction of borehole fluid with the formation.
Types and Associated ProblemsThere are four different types of borehole instabilities: hole closure or narrowing, hole enlargement or washouts, fracturing, and collapse. Fig. 10.7 illustrates hole-instability problems.
Hole Closure. Hole closure is a narrowing time-dependent process of borehole instability. It sometimes is referred to as creep under the overburden pressure, and it generally occurs in plastic-flowing shale and salt sections. Problems associated with hole closure are an increase in torque and drag, an increase in potential pipe sticking, and an increase in the difficulty of casings landing.
Hole Enlargement. Hole enlargements are commonly called washouts because the hole becomes undesirably larger than intended. Hole enlargements are generally caused by hydraulic erosion, mechanical abrasion caused by drillstring, and inherently sloughing shale. The problems associated with hole enlargement are an increase in cementing difficulty, an increase in potential hole deviation, an increase in hydraulic requirements for effective hole cleaning, and an increase in potential problems during logging operations.
Fracturing. Fracturing occurs when the wellbore drilling-fluid pressure exceeds the formation-fracture pressure. The associated problems are lost circulation and possible kick occurrence.
Collapse. Borehole collapse occurs when the drilling-fluid pressure is too low to maintain the structural integrity of the drilled hole. The associated problems are pipe sticking and possible loss of well.
Principles of Borehole Instability
Before drilling, the rock strength at some depth is in equilibrium with the in-situ rock stresses (effective overburden stress, effective horizontal confining stresses). While a hole is being drilled, however, the balance between the rock strength and the in-situ stresses is disturbed. In addition, foreign fluids are introduced, and an interaction process begins between the formation and borehole fluids. The result is a potential hole-instability problem. Although a vast amount of research has resulted in many borehole-stability simulation models, all share the same shortcoming of uncertainty in the input data needed to run the analysis. Such data include in-situ stresses, pore pressure, rock mechanical properties, and, in the case of shale, formation and drilling-fluids chemistry.
Mechanical Rock-Failure Mechanisms
Mechanical borehole failure occurs when the stresses acting on the rock exceed the compressive or the tensile strength of the rock. Compressive failure is caused by shear stresses as a result of low mud weight, while tensile failure is caused by normal stresses as a result of excessive mud weight.
The failure criteria that are used to predict hole-instability problems are the maximum-normal-stress criterion for tensile failure and the maximum strain energy of distortion criterion for compressive failure. In the maximum-normal-stress criterion, failure is said to occur when, under the action of combined stresses, one of the acting principal stresses reaches the failure value of the rock tensile strength. In the maximum of energy of distortion criterion, failure is said to occur when, under the action of combined stresses, the energy of distortion reaches the same energy of failure of the rock under pure tension.
More than 75% of drilled formations worldwide are shale formations. The drilling cost attributed to shale-instability problems is reported to be in excess of one-half billion U.S dollars per year. The cause of shale instability is two-fold: mechanical (stress change vs. shale strength environment) and chemical (shale/fluid interaction—capillary pressure, osmotic pressure, pressure diffusion, borehole-fluid invasion into shale).
Mechanical Instability. As stated previously, mechanical rock instability can occur because the in-situ stress state of equilibrium has been disturbed after drilling. The mud in use with a certain density may not bring the altered stresses to the original state; therefore, shale may become mechanically unstable.
Chemical Instability. Chemical-induced shale instability is caused by the drilling-fluid/shale interaction, which alters shale mechanical strength as well as the shale pore pressure in the vicinity of the borehole walls. The mechanisms that contribute to this problem include capillary pressure, osmotic pressure, pressure diffusion in the vicinity of the borehole walls, and borehole-fluid invasion into the shale when drilling overbalanced.
Capillary Pressure. During drilling, the mud in the borehole contacts the native pore fluid in the shale through the pore-throat interface. This results in the development of capillary pressure, pcap , which is expressed as
where σ is the interfacial tension, ϴ is the contact angle between the two fluids, and r is the pore-throat radius. To prevent borehole fluids from entering the shale and stabilizing it, an increase in capillary pressure is required, which can be achieved with oil-based or other organic low-polar mud systems.
Osmotic Pressure. When the energy level or activity in shale pore fluid, as , is different from the activity in drilling mud, am , water movement can occur in either direction across a semipermeable membrane as a result of the development of osmotic pressure, pos , or chemical potential, μc . To prevent or reduce water movement across this semipermeable membrane that has certain efficiency, Em, the activities need to be equalized or, at least, their differentials minimized. If am is lower than as , it is suggested to increase Em and vice versa. The mud activity can be reduced by adding electrolytes that can be brought about through the use of mud systems such as seawater, saturated-salt/polymer, KCl/NaCl/polymer, and lime/gypsum.
Pressure Diffusion. Pressure diffusion is a phenomenon of pressure change near the borehole walls that occurs over time. This pressure change is caused by the compression of the native pore fluid by the borehole-fluid pressure, pwfl, and the osmotic pressure, pos.
Borehole Fluid Invasion into Shale. In conventional drilling, a positive differential pressure (the difference between the borehole-fluid pressure and the pore-fluid pressure) is always maintained. As a result, borehole fluid is forced to flow into the formation (fluid-loss phenomenon), which may cause chemical interaction that can lead to shale instabilities. To mitigate this problem, an increase of mud viscosity or, in extreme cases, gilsonite is used to seal off microfractures.
Several models in the literature address wellbore-stability analysis. These include very-simple to very-complex models such as linear elastic, nonlinear, elastoplastic, purely mechanical, and physicochemical. Regardless of the model, the data needed include rock properties (Poisson ratio, strength, modulus of elasticity); in-situ stresses (overburden, horizontal); pore-fluid pressure and chemistry; and mud properties and chemistry.
Other than the mud data, the data are often compounded with problems of availability and/or uncertainties. However, sensitivity analysis can be conducted by assuming data for the many variables to establish safety windows for mud selection and design.
Total prevention of borehole instability is unrealistic because restoring the physical and chemical in-situ conditions of the rock is impossible. However, the drilling engineer can mitigate the problems of borehole instabilities by adhering to good field practices. These practices include proper mud-weight selection and maintenance, the use of proper hydraulics to control the ECD, proper hole-trajectory selection, and the use of borehole fluid compatible with the formation being drilled. Additional field practices that should be followed are minimizing time spent in open hole; using offset-well data (use of the learning curve); monitoring trend changes (torque, circulating pressure, drag, fill-in during tripping); and collaborating and sharing information.
A mud is said to be contaminated when a foreign material enters the mud system and causes undesirable changes in mud properties, such as density, viscosity, and filtration. Generally, water-based mud systems are the most susceptible to contamination. Mud contamination can result from overtreatment of the mud system with additives or from material entering the mud during drilling.
Common Contaminants, Sources, and Treatments
The most common contaminants to water-based mud systems are solids (added, drilled, active, inert); gypsum/anhydrite (Ca
); cement/lime (Ca++
); makeup water (Ca++
); soluble bicarbonates and carbonates (HCO3−, CO3—); soluble sulfides (HS−, S—); and salt/salt water flow (Na+
Solids Contamination. Solids are materials that are added to make up a mud system (bentonite, barite) and materials that are drilled (active and inert). Excess solids of any type are the most undesirable contaminant to drilling fluids. They affect all mud properties. It has been shown that fine solids, micron and submicron sized, are the most detrimental to the overall drilling efficiency and must be removed if they are not a necessary part of the mud makeup. The removal of drilled solids is achieved through the use of mechanical separating equipment (shakers, desanders, desilters, and centrifuges). Shakers remove solids in the size of cuttings (approximately 140μ or larger). Desanders remove solids in the size of sand (down to 50μ). Desilters remove solids in the size of silt (down to 20μ). When solids become smaller than the cutoff point of desilters, centrifuges may have to be used. Chemical flocculants are sometimes used to flocculate fine solids into a bigger size so that they can be removed by solids-removal equipment. Total flocculants do not discriminate between various types of solids, while selective flocculants will flocculate drilled solids but not the added barite solids. As a last resort, dilution is sometimes used to lower solids concentration.
Calcium-Ions Contamination. The sources of calcium ions are gypsum, anhydrite, cement, lime, seawater, and hard/brackish makeup water. The calcium ion is a major contaminant to freshwater-based sodium-clay treated mud systems. The calcium ion tends to replace the sodium ions on the clay surface through a base exchange, thus causing undesirable changes in mud properties such as rheology and filtration. It also causes added thinners to the mud system to become ineffective. The treatment depends on the source of the calcium ion. For example, sodium carbonate (soda ash) is used if the source is gypsum or anhydrite. Sodium bicarbonate is the preferred treatment if the calcium ion is from lime or cement. If treatment becomes economically unacceptable, break over to a mud system, such as gypsum mud or lime mud, that can tolerate the contaminant.
Biocarbonate and Carbonate Contamination. The contaminant ions (CO3—, HCO3−) are from drilling a CO2-bearing formation, thermal degradation of organics in mud, or over treatment with soda ash and bicarbonate. These contaminants cause the mud to have high yield and gel strength and a decrease in pH. Treating the mud system with gypsum or lime is recommended.
Hydrogen Sulfide Contamination. The contaminant ions (HS−, S—) generally are from drilling an H2S-bearing formation. Hydrogen sulfide is the most deadly ion to humans and is extremely corrosive to steel used during drilling operations. (It causes severe embrittlement to drillpipe.) Scavenging of H2S is done by use of zinc, copper, or iron.
Salt/Saltwater Flows. The ions, Na+
Producing Formation Damage
IntroductionProducing formation damage has been defined as the impairment of the unseen by the inevitable, causing an unknown reduction in the unquantifiable. In a different context, formation damage is defined as the impairment to reservoir (reduced production) caused by wellbore fluids used during drilling/completion and workover operations. It is a zone of reduced permeability within the vicinity of the wellbore (skin) as a result of foreign-fluid invasion into the reservoir rock. Fig. 10.8 illustrates formation skin damage.
Borehole fluids are classified as drilling fluids, completion fluids, or workover fluids. Drilling fluids are categorized as mud, gas, or gasified mud. There are two types of mud: water-based (pure polymer, pure bentonite, bentonite/polymer) and oil-based (invert emulsion, oil). Completion and workover fluids are mostly brines and are solids free.
Damage MechanismsFormation damage is a combination of several mechanisms including solids plugging, clay-particle swelling or dispersion, saturation changes, wettability reversal, emulsion blockage, aqueous-filtrate blockage, and mutual precipitation of soluble salts in wellbore-fluid filtrate and formation water.
Solids Plugging. Fig. 10.9 shows that the plugging of the reservoir-rock pore spaces can be caused by the fine solids in the mud filtrate or solids dislodged by the filtrate within the rock matrix. To minimize this form of damage, minimize the amount of fine solids in the mud system and fluid loss.
Clay-Particle Swelling. This is an inherent problem in sandstone that contains water-sensitive clays. When a fresh-water filtrate invades the reservoir rock, it will cause the clay to swell and thus reduce or totally block the throat areas.
Saturation Change. Production is predicated on the amount of saturation within the reservoir rock. When a mud-system filtrate enters the reservoir, it will cause some change in water saturation and, therefore, potential reduction in production. Fig. 10.10 shows that high fluid loss causes water saturation to increase, which results in a decrease of rock relative permeability. See the chapter on transport properties in the General Engineering volume of this Handbook for additional information.
Wettability Reversal. Reservoir rocks are water-wet in nature. It has been demonstrated that while drilling with oil-based mud systems, excess surfactants in the mud filtrate that enter the rock can cause wettability reversal. It has been reported from field experience and demonstrated in laboratory tests that as much as 90% in production loss can be caused by this mechanism. Therefore, to guard against this problem, the amount of excess surfactants used in oil-based mud systems should be kept at a minimum.
Emulsion Blockage. Inherent in oil-based mud systems is the use of excess surfactants. These surfactants enter the rock and can form an emulsion within the pore spaces, which hinders production through emulsion blockage.
Aqueous-Filtrate Blockage. While drilling with water-based mud, the aqueous filtrate that enters the reservoir can cause some blockage that will reduce the production potential of the reservoir.
Precipitation of Soluble Salts. Any precipitation of soluble salts, whether from the use of salt mud systems or from formation water or both, can cause solids blockage and hinder production. For more information, see the Formation Damage chapter in the Production Operations Engineering volume of this Handbook.
IntroductionThroughout the last decade, many studies have been conducted to gain understanding on hole cleaning in directional-well drilling. Laboratory work has demonstrated that drilling at an inclination angle greater than approximately 30° from vertical poses problems in cuttings removal that are not encountered in vertical wells. Fig. 10.11 illustrates that the formation of a moving or stationary cuttings bed becomes an apparent problem if the flow rate for a given mud rheology is below a certain critical value.
Inadequate hole cleaning can lead to costly drilling problems such as mechanical pipe sticking, premature bit wear, slow drilling, formation fracturing, excessive torque and drag on drillstring, difficulties in logging and cementing, and difficulties in casings landing. The most prevalent problem is excessive torque and drag, which often leads to the inability of reaching the target in high-angle/extended-reach drilling.
Factors in Hole CleaningAnnular-Fluid Velocity. Flow rate is the dominant factor in cuttings removal while drilling directional wells. An increase in flow rate will result in more efficient cuttings removal under all conditions. However, how high a flow rate can be increased may be limited by the maximum allowed ECD, the susceptibility of the openhole section to hydraulic erosion, and the availability of rig hydraulic power.
Hole Inclination Angle. Laboratory work has demonstrated that when hole angle increases from zero to approximately 67° from vertical, hole cleaning becomes more difficult, and therefore, flow-rate requirement increases. The flow-rate requirements reach a maximum at approximately 65 to 67° and then slightly decrease toward the horizontal. Also, it has been shown that at 25 to approximately 45°, a sudden pump shutdown can cause cuttings sloughing to bottom and may result in a mechanical pipe-sticking problem. Although, hole inclination can lead to cleaning problems, it is mandated by the needs of drilling inaccessible reservoir, offshore drilling, avoiding troublesome formations, and side tracking and to drill horizontally into the reservoir. Objectives in total field development (primary and secondary production), environmental concerns, and economics are some of the factors that intervene in hole angle selection.
Drillstring Rotation. Laboratory studies have shown and field cases have reported that drillstring rotation has moderate to significant effects in enhancing hole cleaning. The level of enhancement is a combined effect of pipe rotation, mud rheology, cuttings size, flow rate, and, very importantly, the string dynamic behavior. It has been proved that the whirling motion of the string around the wall of the borehole when it rotates is the major contributor to hole cleaning enhancement. Also, mechanical agitation of the cuttings bed on the low side of the hole and exposing the cuttings to higher fluid velocities when the pipe moves to the high side of the hole are results of pipe whirling action.
Although there is a definite gain in hole cleaning caused by pipe rotation, there are certain limitations to its implementation. For example, during angle building with a downhole motor (sliding mode), rotation cannot be induced. With the new steering rotary systems, this is no longer a problem. However, pipe rotation can cause cyclic stresses that can accelerate pipe failures due to fatigue, casing wear, and, in some cases, mechanical destruction to openhole sections. In slimhole drilling, high pipe rotation can cause high ECDs due to the high annular-friction pressure losses.
Hole/Pipe Eccentricity. In the inclined section of the hole, the pipe has the tendency to rest on the low side of the borehole because of gravity. This creates a very narrow gap in the annulus section below the pipe, which causes fluid velocity to be extremely low and, therefore, the inability to transport cuttings to surface. As Fig. 10.12 illustrates, when eccentricity increases, particle/fluid velocities decrease in the narrow gap, especially for high-viscosity fluid. However, because eccentricity is governed by the selected well trajectory, its adverse impact on hole cleaning may be unavoidable.
Fig. 10.12—Fluid velocity profile in eccentric annulus (after Hzouz et al.).
Rate of Penetration. Under similar conditions, an increase in the drilling rate always results in an increase in the amount of cuttings in the annulus. To ensure good hole cleaning during high-rate-of-penetration (ROP) drilling, the flow rate and/or pipe rotation have to be adjusted. If the limits of these two variables are exceeded, the only alternative is to reduce the ROP. Although a decrease in ROP may have a detrimental impact on drilling costs, the benefit of avoiding other drilling problems, such as mechanical pipe sticking or excessive torque and drag, can outweigh the loss in ROP.
Mud Properties. The functions of drilling fluids are many and can have unique competing influences. The two mud properties that have direct impact on hole cleaning are viscosity and density. The main functions of density are mechanical borehole stabilization and the prevention of formation-fluid intrusion into the annulus. Any unnecessary increase in mud density beyond fulfilling these functions will have an adverse effect on the ROP and, under the given in-situ stresses, may cause fracturing of the formation. Mud density should not be used as a criterion to enhance hole cleaning.
Viscosity, on the other hand, has the primary function of the suspension of added desired weighting materials such as barite. Only in vertical-well drilling and high-viscosity pill sweep is viscosity used as a remedy in hole cleaning.
Cuttings Characteristics. The size, distribution, shape, and specific gravity of cuttings affect their dynamic behavior in a flowing media. The specific gravity of most rocks is approximately 2.6; therefore, specific gravity can be considered a nonvarying factor in cuttings transport. The cuttings size and shape are functions of the bit types (roller cone, polycrystalline-diamond compact, diamond matrix), the regrinding that takes place after they are generated, and the breakage by their own bombardment and with the rotating drillstring. It is impossible to control their size and shape even if a specific bit group has been selected to generate them. Smaller cuttings are more difficult to transport in directional-well drilling; however, with some viscosity increase and pipe rotation, fine particles seem to stay in suspension and, therefore, are easier to transport.
Hydrogen-Sulfide-Bearing Zones and Shallow Gas
Drilling H2S-bearing formations poses one of the most difficult and dangerous problems to humans and equipment. If it is known or anticipated, there are very specific requirements to abide by in accordance with Intl. Assn. of Drilling Contractors rules and regulations. Shallow gas may be encountered at any time in any region of the world. The only way to combat this problem is to never shut in the well; divert the gas flow through a diverter system instead. 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 shut in, formation fracturing is more likely to occur, which will result in the most severe blowout problem, underground blow.
Equipment and Personnel-Related Problems
The integrity of drilling equipment and its maintenance are major factors in minimizing drilling problems. Proper rig hydraulics (pump power) for efficient bottom and annular hole cleaning, proper hoisting power for efficient tripping out, proper derrick design loads and drilling line tension load to allow safe overpull in case of a sticking problem, and well-control systems (ram preventers, annular preventers, internal preventers) that allow kick control under any kick situation are all necessary for reducing drilling problems. Proper monitoring and recording systems that monitor trend changes in all drilling parameters and can retrieve drilling data at a later date, proper tubular hardware specifically suited to accommodate all anticipated drilling conditions, and effective mud-handling and maintenance equipment that will ensure that the mud properties are designed for their intended functions are also necessary.
Given equal conditions during drilling/completion operations, personnel are the key to the success or failure of those operations. Overall well costs as a result of any drilling/completion problem can be extremely high; therefore, continuing education and training for personnel directly or indirectly involved is essential to successful drilling/completion practices.
|αm||=||activity in drilling mud, dimensionless|
|αs||=||activity in shale pore fluid, dimensionless|
|Ac||=||area of contact, L2 , in.2|
|Dh||=||diameter of the hole, L, in.|
|Dop||=||outside diameter of the pipe, L, in.|
|f||=||coefficient of friction, dimensionless|
|Fl||=||lateral force, F, lbf|
|Fp||=||pull force, F, lbf|
|hmc||=||mudcake thickness, L, in.|
|Lep||=||length of the permeable zone, L, in.|
|pcap||=||capillary pressure, F/L2, psi|
|pff||=||formation-fluid pressure, F/L2, psi|
|pm||=||mud pressure, F/L2, psi|
|pos||=||osmotic pressure, F/L2, psi|
|r||=||pore-throat radius, L, in.|
|T||=||tension in the drillstring just above the key-seat area, F, lbf|
|Δp||=||differential pressure, F/L2 , psi|
|Δλαf||=||additional mud weight caused by friction pressure loss in annulus, F/L3, lbm/gal|
|Δλs||=||additional mud weight caused by surge pressure, F/L3, lbm/gal|
|ϴ||=||contact angle between the two fluids, degrees|
|ϴdl||=||abrupt change in hole angle, degrees|
|λeq||=||equivalent mud circulating density, F/L3, lbm/gal|
|λfrac||=||formation-pressure fracture gradient in equivalent mud weight, F/L3, lbm/gal|
|λmh||=||static mud weight, F/L3, lbm/gal|
|μc||=||chemical potential, dimensionless|
|σ||=||interfacial tension, F/L, lbf/in.|
- Cite error: Invalid
<ref>tag; no text was provided for refs named
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SI Metric Conversion Factors
|ft||×||3.048*||E − 01||=||m|
|gal||×||3.785 412||E − 03||=||m3|
|lbm||×||4.535 924||E − 01||=||kg|
Conversion factor is exact.