Pressure Control – Indicators of Increasing Pressure

•Pressure indicators are divided into two groups:
–I. Engineering.
–II. Geological.

Engineering Indicators of Increasing Pressure

•Changes in Rate of Penetration (ROP)
–ROP increases while drilling the transition zone.
–While drilling normally pressured shale sections, the ROP will decrease with depth if drilling parameters such as weight-on-bit, RPM, bit types, hydraulics and mud weight remain fairly constant.
–There will be a marked reduction in ROP as the pressure seal is penetrated.
–After penetrating the seal in sur-normally pressured formations, there will be an increase in ROP.
–This is due to the higher porosity of the sur-normal pressured zone.
•Decreases in dcsexponent trend
–Calculations for “d exponent”and “dcs exponent”can be made to normalize ROP data and predict the magnitude of increasing formation pressure.
–Trends can be graphically established using complicated formula
•Changes in rotary torque
–Rotary torque may increase rapidly in the transition zone.
–Torque increases gradually with depth because the contact friction between the drillstring and the wellbore increases with depth.
–Torque will increase in the transition zone because a larger volume of shale cuttings will enter the wellbore. Shale tends to close in the hole, causing additional contact with the drillstring and impeding bit rotation.
•Changes in drag
–An increase in drag may be experienced while making connections in the transition zone.
–After the kellyis drilled down, the recommended practice is to pick up 5 to 10 ft (to allow for working the drill pipe if it sticks), turn the pumps off and pull the kellyfrom the hole.
•Changes in rotary torque
–Extra cuttings may enter the wellbore when the transition zone is penetrated.
–The hole may also tend to close-in around the drill collars and bit.
–Some transition zone shales tend to flow under differential pressure.
–There have been instances where it was necessary to backreamand circulate to trip out of the hole.
•Kicks
–An actual kick is the most obvious indication of an increase in pressure.
–Any pit gain, if not accounted for, is an indication of an influx of formation fluid (kick).
–When this happens, the amount of fluid returning increases, and the flow sensor records the increase.
•Kicks Cont.
–When approaching a transition zone if an increase in pit volume or flow is detected, drilling should be stopped and the well checked for flow.
–If the well continues to flow, it should be shut in.
•Filling the hole on trips
–When pulling the drillstring out of the hole, the amount of pipe in the hole is reduced, and the mud level drops.
–The volume can be calculated from the size and weight of the pipe and the length of the pipe removed, so that an appropriate amount of mud can be pumped into the hole to fill it up.
•Filling the hole on trips
–If the drillstring volume is not replaced and the mud column drops, then the hydrostatic pressure is reduced and may result in a kick.
–If the hydrostatic pressure is reduced to less than formation pressure, formation fluids will flow into the well.
–If the hole takes less mud than the calculated displacement volume for the number of stands pulled, fluid is entering the wellbore.
–This signals an impending kick.

Pressure Control – Subsurface Pressures

•Many different pressures are involved in drilling and controlling oil and gas wells.
•It is important to understand these pressures and how they are used to detect and control formation pressures.
•Pressure is defined as force per unit area:
Pressure (psi) = force (lb) /area (in.2)
•Hydrostatic pressure (PHYD) is the pressure caused by the density or Mud Weight (MW) and True Vertical Depth (TVD) of a column of fluid.
–The hole size and shape of the fluid column have no effect on hydrostatic pressure since, at a given depth, pressure is equal in all directions.
•PHYDis calculated by:
–PHYD(psi) =0.052 x MW (lb/gal) x TVD (ft)
–0.052 = The units conversion factor equal to:
12 in./ft/231 in.3/gal
or 0.052 gal/(in.2x ft)
•What is the hydrostatic pressure of a fluid column for the following conditions?
–MW = 12.8 lb/gal
–MD (Measured Depth) = 14,300 ft
–TVD = 13,200 ft
•The hydrostatic pressure is always calculated using the TVD.
PHYD= 0.052 x 12.8 x 13,200
= 8,786 psi at TVD
•Hydrostatic pressure gradient is the pressure increase per unit of vertical depth.
–PHYDG(psi/ft) = 0.052 x MW (lb/gal)
•What is the pressure gradient of a 12.0 lb/gal mud?
PHYDG(psi) = 0.052 x 12.0
=0.624 psi/ft
•Typical pressure gradients are:
–Freshwater 0.433 psi/ft
–Seawater 0.444 psi/ft
–Marine formation water
–(100,000 mg/l salt) 0.465 psi/ft
–Saturated saltwater
–(10 lb/gal) 0.520 psi/ft
–16-lb/gal mud 0.832 psi/ft
–19.2-lb/gal mud 1.0 psi/ft
Formation pressure (Pform) is the fluid pressure exerted within the pore spaces of any oil, water or gas formation, and is commonly called pore pressure.
•Normal pressure is the hydrostatic pressure exerted by a column of fluid equal to the density of the native fluid that existed in the geological environment when the solids were deposited.
–Since more wells are drilled in sediments characterized by marine formation water with about 100,000 mg/l salt, a gradient of 0.465 psi/ft will be used as the normal gradient for purposes of this discussion.
–Deviations from normal hydrostatic pressures are referred to as being abnormal —sur-pressures (high) and sub-pressures (low).
Indicators of Increasing Pressure

Pressure Control

•Despite efforts to understand and control formation pressures, blowouts still occur.
•A blowout is an uncontrolled flow of formation fluids as the result of failure to control subsurface pressures.
•Blowouts can occur at the surface or into an underground formation.
•Nearly every well drilled has the potential to blow out.
•Experience has shown that blowouts occur as the result of human error and/or mechanical failures.
•However, a carefully planned, continuously supervised pressure-control program will lessen the possibility of a blowout considerably.
•It is important to identify high formation pressures before drilling, to detect pressure changes while drilling, and to control them safely during drilling and completion operations.
•Pressure control can be divided into three categories:
•Primary control.
–The proper use of hydrostatic pressure to overbalance the formation and prevent unwanted formation fluids from entering the wellbore.
–The advantages of control at this level are self-evident.
•Secondary control.
–The use of equipment to control the well in the event primary control is lost.
–Formation fluids that have entered the annulus can cause a blowout quickly if not properly controlled.
•Tertiary control.
–The use of equipment and hydrostatic pressure to regain control once a blowout has occurred.
–This could involve the drilling of a relief well.
–Although tertiary control is normally handled by experts, many things can be done during the planning and drilling of a relief well to simplify the final kill procedure and regain control of the well.
A kick is an influx of formation fluid into the well.
A blowout is an uncontrolled kick.
•Failure of primary control.
–Any event or chain of events that create a negative differential pressure between the hydrostatic pressure of the drilling fluid and the formation pressure can cause a “kick.”
•The most common causes of a kick are:
–Failure to keep the hole full of mud during trips.
–Insufficient mud weight.
–Lost circulation causing the hydrostatic pressure to be reduced.
–Swabbing in when pulling out of the hole.
–Improper casing design and pore pressure prediction.
•Failure of secondary control.
–It has been estimated that 95% of the wells in which secondary control is lost arrive at that condition as the result of either poor maintenance and inadequate testing programs, which result in leaks that erode pressure-control equipment, or inadequate crew training, which results in miss-use or no use at all of pressure control equipment.

Mud Related Drilling Problems Foaming

•A small amount of foaming occurs in most drilling muds.
•Foaming occurs due to high interfacial surface tension phenomena or mechanical air entrapment.
•Most foaming occurs on the surface and normally does not adversely affect the mud.
•If the foam or air bubbles become dispersed throughout the mud, the pump may stroke in an erratic manner, which could cause serious mechanical damages
•Air leak in mud pump
•The discharges of the desilter/desanderor mud hopper can whip air into the mud.
•High chloride content in mud.
–Salt water muds have an inherent tendency to foam.
•Lignosulfonateshave a tendency to foam, especially in high concentrations.
Causes •Over treatment of mud detergents. •Air entrapped in drill pipe after tripping. •High pressure-low volume formations or swabbing when tripping may cause the mud to become gas cut. •Thick mud containing a large amount of drilled solids are particularly susceptible to foaming. •Bacteria fermentation of the mud.
Treatment
•The mud has to be thinned in order to permit effective removal and prevent a build-up of foam.
–Lower the viscosity, YP and in particular the Gel Strengths with dispersants (Desco) or Lignite as required to allow the foam to dissipate.
•Alcohol base defoamersor Aluminum Sterate(oil soluble only; mix with diesel oil) may be added directly into the suction tank.
•Avoid air leaks in pumps and suctions.
Prevent whipping air into mud.
–Submerge all surface guns, hopper and solids control equipment discharges.
•"Roll" the tanks with the submerged guns to allow the air or gas bubbles to escape into the atmosphere.
•If a wash gun is available, spray the surface of the mud with a fine spray of diesel or water.

Mud Related Drilling Problems Formation Damage-Corrosion

•Formation Damage:

–Damage to the productivity of a well resulting from invasion into the formation by mud particles or mud filtrates. –Asphalt from crude oil will also damage some formations. •Common mechanisms for formation damage are: –Mud or drill solids invading the formation matrix, plugging pores. –Swelling of formation clays within the reservoir, reducing permeability. –Precipitation of solids as a result of mud filtrate and formation fluids being incompatible. –Precipitation of solids from the mud filtrate with other fluids, such as brines or acids, during completion or stimulation procedures. –Mud filtrate and formation fluids forming an emulsion, restricting permeability. •Prevention –Formation damage can be minimized by using a Drill In fluid •Drill In Fluids should contain non-damaging polymers, bridging agent •Should have superior regain permeability •May have shale or clay inhibitors •Should be easy to clean up

Corrosion

•Corrosion is the destruction of metal through electrochemical action between metal and its environment. •Corrosion can be costly in terms of damage to pipe and well parts and can even result in the loss of an entire well. •About 75 to 85 percent of drillpipe loss can be attributed to corrosion. •Other areas affected by corrosion include pump parts, bits, and casing. •Factors affecting corrosion include: –Temperature. Generally, corrosion rates double with every 55°F (31°C) increase in temperature. –Velocity. The higher the mud velocity, the higher the rate of corrosion due to film erosion (oxide, oil, amine, etc.). –Solids. Abrasive solids remove protective films and cause increased corrosive attack. –Metallurgical factors. Mill scale and heat treatment of pipe can cause localized corrosion. –Corrosive agents. Corrosive agents such as oxygen, carbon dioxide, and hydrogen sulfide can increase corrosion and lead to pipe failure. •Types of Corrosion –Uniform corrosion •Even corrosion pattern over surfaces –Localized corrosion •like corrosion pattern over surfaces –Pitting •Highly localized corrosion that results in the deep penetration of surfaces •Corrosive agents found in drilling fluids include: –Oxygen –Hydrogen sulfide –Carbon dioxide –Bacteria –Dissolved salts –Mineral scale

Corrosion -Oxygen

•Oxygen causes a major portion of corrosion damage to drilling equipment. •Oxygen acts by removing protective films; this action causes accelerated corrosion and increased pitting under deposits. •The four primary sources of oxygen are: –Water additions –Actions of mixing and solids-control equipment –Aerated drilling fluids –The atmosphere •If oxygen corrosion is suspected treatment would include adding an oxygen scavengers –Many types of oxygen scavengers exist –Manufactures recommended treatment should be followed in this case

Corrosion -Hydrogen sulfide

•Hydrogen sulfide can enter the mud system from: –Formation fluids containing hydrogen sulfide –Bacterial action on sulfur-containing compounds in drilling mud –Thermal degradation of sulfur-containing drilling fluid additives –Chemical reactions with tool-joint thread lubricants containing sulfur •Hydrogen sulfide is soluble in water. •Dissolved hydrogen sulfide behaves as a weak acid and causes pitting. •Hydrogen ions at the cathodicareas may enter the steel instead of evolving from the surface as a gas. •This process can result in hydrogen blistering in low-strength steels or hydrogen embrittlement in high-strength steels. •Both the hydrogen and sulfide components of hydrogen sulfide can contribute to drillstring failures. •Hydrogen sulfide corrosion is mitigated by increasing the pH to above 9.5 and by using sulfide scavengers and film-forming inhibitors. –Sulfide scavengers include Zinc Carbonate, Zinc Oxide and other specialty chemical products –Most film forming inhibitors are amine inhibitors, many are available

Corrosion –Carbon Dioxide

•Carbon dioxide is found in natural gas in varying quantities. •When combined with water, carbon dioxide forms carbonic acid and decreases the water's pH, which increases the water's corrosivity. •While carbon dioxide is not as corrosive as oxygen, it can cause pitting. •Maintaining the correct pH is the primary treatment for carbon dioxide contamination. •Either lime or caustic soda can be used to maintain pH.

Corrosion –Bacteria

•Microorganisms can cause fermentation of organic mud additives, changing viscosity and lowering pH. •A sour odor and gas are other indicators that bacteria are present. •Degradation of mud additives can result in increased maintenance cost •Microbiocidesare used to control bacteria in drilling environments

Corrosion –Dissolved Salts

•Dissolved salts increase corrosion by decreasing the electrical resistance of drilling fluids and increasing the solubility of corrosion by-products. •Some of these byproducts can cause a scale or film to form on the surface of the metal. •Amine filming agents added to the metal will aid in reducing corrosion due to dissolved salts •Mineral scale deposits set up conditions for local corrosion-cell activity. •The continuous addition of a scale inhibitor can control the formation of scale deposits.

Mud Related Drilling ProblemsLost Circulation

Lost circulation or loss of returns describes the complete or partial loss of fluid to the formation as a result of excessive hydrostatic and annular pressure drop. •Lost circulation is characterized by a reduction in the rate of mud returns from the well compared to the rate at which it is pumped downhole (flow out <> •If the annulus of the well will not remain full even when circulation of the fluid has ceased, the hydrostatic pressure will reduce until the differential pressure between the mud column and the loss zone is zero. –This may induce formation fluids from other zones, previously controlled by the mud hydrostatic pressure, to flow into the wellbore resulting in a kick, blowout, or underground blowout. –It may also cause previously stable formations to collapse into the wellbore. •Permeable or fractured formations can result in partial or complete loss of circulation. •Formation fractures can be natural or caused by excessive drilling fluid pressure on a structurally weak formation. •Once a fracture has been induced, the fracture will widen and take more mud at a lower pressure. •To avoid inducing formation fractures: –Maintain the minimum equivalent-circulating density (ECD) and mud weight. –Avoid pressure surges.

Lost Circulation –Fractured

•Permeable or fractured formations can result in partial or complete loss of circulation. •Formation fractures can be natural or caused by excessive drilling fluid pressure on a structurally weak formation. •Once a fracture has been induced, the fracture will widen and take more mud at a lower pressure. •To avoid inducing formation fractures: –Maintain the minimum equivalent-circulating density (ECD) and mud weight. –Avoid pressure surges. •Indication: –Lost circulation of this type is indicated by a complete or partial loss of returns and a decrease in pit volume. •Treatment –If a induced fracture is suspected, the hole can be allowed to heal by pulling into the casing and waiting 6 to 12 hours. –After the waiting period, stage back to bottom and check for full returns. –If full returns have not been established, treat the losses as if they were cavernous/vugularlosses.

Lost Circulation –Permeable

•Permeable and porous formations include: –Loose, noncompactedgravel beds –Shell beds –Reef deposits –Depleted reservoirs •These types of formations cause seepage loss to complete loss of returns. •Indication –Seepage into permeable formations is indicated by partial to full loss of returns and a decrease in pit volume. •Treatment –Reduce mud weight as much as possible. –Treat the system with a combination of fine-to medium-grade lost-circulation products

Lost Circulation –Corrective Measures

•Conventional Lost Circulation pill –Consider using a combination of LCM material with varying sizes to provide for an optimum bridging agent with this type of pill. –Small amounts of Lime may be used to slightly flocculate the Bentonite, to increase the viscosity preventing the LCM material from settling out and plugging the bit. –It is cheaper to obtain the viscosity using small amounts of Lime. –The Lime addition will also provide a higher fluid loss than the Gel slurry thereby increasing the sealing rate. •The actual concentration of LCM in the pill may vary; the formulation listed below assumes no jet or very large nozzles in the bit. •Once the approximate point of loss is established, a 15 -30 m3(100-300 bbl) pill should be mixed •Fresh Water15-50 m3(94 –310 bbl) •Soda Ash0.50-0.75 kg/m3(0.15-0.25ppb) •Caustic Soda0.50-0.75 kg/m3(0.15-0.25ppb) •Bentonite70-75 kg/m3(25-26 ppb) •Sawdust15 kg/m3(5 ppb) •FibreSeal15 kg/m3(5 ppb) •WalnutShells/Mica 15 kg/m3(5 ppb) •Lime1.0-1.5 kg/m3(0.35 –0.5 ppb) •Once the pill has been mixed, spot just above the loss zone by pumping slowly; 160-320 litres/min. (1-2 bbl./min.) until the hole is full and circulation is regained. •If the hole remains full, close the hydriland squeeze the annulus with 300-500 kPa(50-75 psi) for 30 minutes. •If this procedure fails, repeat once. •A second failure may indicate that another technique may be in order. Effective control of lost circulation into a permeable zone may require a broad range of particles •Gunk Squeeze –When you are faced with a lost circulation problem and you are using an oil/synthetic mud, mix the gunk squeeze with water and Organofilic Clay instead of oil/synthetic and bentonite. •To mix a gunk squeeze, follow these steps: –Drain and clean the mixing tank thoroughly. •Prepare a gunk slurry –Pump the following in this order: •Spacer to cover approx. 500' of drillstring •Squeeze to cover approx. 2 times open hole volume •Spacer to cover approx. 500' of drillstring –The spacer fluid should have the same base fluid as the squeeze. –Displace the squeeze to the bit. –Close blowout preventers (BOPs). –Pump down the drillpipe and annulus in equal volumes until the squeeze and spacer are displaced from the drillpipe. –Maintain equal pressure on drillpipe and casing.

Mud Related Drilling Problems Packing Off-Under gauge Hole

Packing Off

•Drilling-fluid systems with poor suspension characteristics exhibit strong packing-off tendencies
•Factors that can lead to caving of the formation include:
–Pressure imbalance
–Shale hydration
–Bottom hole assembly striking the wall
Massive particle caving sticks the drill bit.•The Solution is to increase the suspension characteristics of the mud

Mud Related Drilling Problems
Unde gauge Hole

•Under gauge hole is a condition where the borehole is smaller than the bit diameter used to drill the section.
•Under gauge hole can result from any of the following causes:
–Plastic flowing formations
–Wall-cake buildup in a permeable formation
–Swelling shales
•A plastic flowing formation is a formation that is plastic (easily deformable when stressed) and can flow into the borehole.
–When these types of formations are penetrated by the bit, the hole is at gauge.
–However, when the hydrostatic pressure exerted by the column of drilling fluid is less than the hydrostatic pressure of the formation, under balance results, the formation flows, and hole diameter decreases.
•Undergauge hole is a common problem when drilling a thick salt section with an oil mud.
–The salt can flow into the borehole and make the section undergauge.
–When plastic salt formations exist, they are usually below 5,000 feet.
–Spotting fresh water is the best way to free the pipe from a plastic salt formation.
•Wall-cake buildup occurs when the drilling fluid has poor filtration control across a permeable zone.
•Excessive wall-cake buildup can also be caused by:
–High percentage of low-gravity solids
–High differential pressures (excessive mud weights)

Mud Related Drilling Problems Differential Sticking –Reduce Hydrostatic-Key Seating

Reduce Hydrostatic

•Reducing the hydrostatic pressure and therefore the differential pressure with the use of nitrogen has been tried as another alternative.
–Considerations regarding wellbore stability and potential well control problems must be evaluated prior to implementing this method.
–The well is displaced partially or completely with nitrogen
–The method will normally have some hole sloughing issues related with it

Key Seating

•Keyseating is a situation frequently encountered in deviated or crooked holes when the drillpipe wears into the wall. The normal drilling rotation of the drillstring cuts into the formation wall in deviated areas where the drillpipe tension creates pressure against the sides of the hole.
•Keyseating is diagnosed when the drillpipe can be reciprocated within the range of tool joint distances or until collar reaches the keyseat, while pipe rotation and circulation remain normal
–May not be able to rotate when the tool joint is jammed into the keyseat
he friction generated by drillpipe rotation against the bore wall cuts a narrow channel, or keyseat, into the formation.
•A preventive measure is to carefully control upper hole deviation and dogleg severity throughout the well path.
–This action will eliminate the force that leads to keyseat creation.
–Once a keyseat is formed, the best solution is to ream out the small-diameter portions of the hole with reaming tools.
–This action will solve the immediate stuck-pipe problem, but the keyseat can be formed again unless preventive steps are taken.

Attach a reamer to the drill assembly to widen the keyseat.