Pete 4060 Final Study Guide

PETE 4060 MIDTERM STUDY GUIDE RIG EQUIPMENT & FUNCTIONS: 







Power System: o Diesel electric generator package: supplies power o Diesel Engine: powers mud pump o AC Electric Motor: Torque at constant speed o DC Electric Motor: Operate over larger range of torques Hoisting System: o Derrick: supports load o Traveling Block: lifts/lowers things into wellbore o Drilling Line: would steel wire o Drawworks: houses drum and drilling line o Crown Block: strings multiple lines—does not move Rotating System: o Drill pipe: rotate bit in bottomhole; conducts drilling fluid o Drill Collar: provides WOB o Bit: Breaks rock o Rotary table: located on rig floor; creates strong torque for bit o Rotary drive bushing (Kelly bushing): adapter that connects Kelly to rotary table o Kelly: transmit rotary motions from rotary table/KB to drillstring o Top drive: turns drillstring; done with 3 joint stands rather than single joint stands

Circulating System: o Mud pump: pumps mud through system





o Mud pits (mud tanks): stores mud o Charge pump: pushes mud from tank to pumps; ensures pumps are filled o Shale shaker: separate cuttings from mud o Bell nipple: directs flow back into tank; flow line Well Control System: o Annular preventer: supports holding in place o Ram preventer: more reliable, closes on higher pressures o Blind ram black (model only): no pipe in hole; prevents tubing, tools, and fluid from blowing out of well o Pipe ram block: closes only one size o Variable bore ram blocks: closes on different sizes o Accumulator (BOP control unit, Koomey Unit): uses pressure to shut-in well o Accumulator Bottle (cutaway): stores hydraulic fluids o Remote BOP Control Panel: controls BOP from remote location o HCR (choke line) valve: gate valve to open BOP o Choke Manifold: used in case choke fails o Remote-operated choke o Choke Control Panel: remotely control choke o Mud-gas separator: separates mud and gas; gas goes to flare, mud goes to tank/pit o Drilling float: check valve; prevents flow back into well o Drill string Safety valve: shut-in well while tripping

Well Monitoring System: o Pit level float sensor: tracks level of mud in pit

o o o o



Gauge protector or gauge boot: monitor separate mud and drill fluid Stroke counter display: rate of strokes Stroke counter sensor: tracks number of full trip Pit level display (“flow show”):shows pit gains and loses; connects to pit level float sensor o Weight indicator: reads and displays weight on drawworks; prevent crushing bit o Drillpipe pressure gauge o Casing pressure gauge o Digital data display: gives all data for pump and choke pressure Well Equipment: o Casing: supports well flow; protects environment from drilling fluids o Christmas tree & Wellhead: control flow of well; hold production casing string o Production tubing: protects environment from produced fluid

GENERAL DRILLING OPERATIONS     

Producing and transmitting power Hoisting equipment for the drilling string, casing and tubing Rotating the bit to make hole Circulation to remove cuttings and maintain fluid density to control formation pressures and therefore keep the wellbore stable Pbh>Pformation

CH.1: DRILLING FLUIDS 



Functions of a drilling fluid: o Clean rock fragments from beneath the bit and carry them to the surface o Exert sufficient hydrostatic pressure against subsurface formations to prevent formation fluids from flowing into the well o Keep the newly drilled borehole open until steel casing can be cemented in the hole o Cool and lubricate the rotating drillstring and bit Properties relating to well control: o Mud density o Mudcake buildup/filtration rate o Viscosity

CH.2: FUNDAMENTALS OF STATIC PRESSURES IN WELLS 

Calculating static pressures throughout a well bore with multiple fluids: o 𝑃@𝑇𝑉𝐷 = 0.052 ∗ (𝑀𝑊) ∗ (𝑇𝑉𝐷) o 𝑃@𝑇𝑉𝐷 = 𝑃𝑠 + Σ[0.052 ∗ 𝑀𝑊𝑖 ∗ 𝑇𝑉𝐷𝑖 ] o Pformation


 If Pwell>Pfracture the formation will fracture & lose returns Converting from pressure to equivalent mud weight (EMW): 𝑃 [𝑝𝑠𝑖]

o

𝑡 𝐸𝑀𝑊[𝑝𝑝𝑔𝑒]@𝑇𝑉𝐷 = 0.52∗𝑇𝑉𝐷[𝑓𝑡]

o

EMWformation<MW<EMWfracture  If EMWform>MW, well will flow and we will take a kick KWM:

o

 

𝐾𝑊𝑀 =

𝑆𝐼𝐷𝐷𝑃 0.052∗𝑇𝑉𝐷

+ 𝑀𝑊

Performing and interpreting leak off tests: o Used to determine fracture pressure; also known as formation strength test and cement integrity o Made by pumping into the well at SCR with a few feet of formation exposed below the shoe and observing the pressure at which the formation will begin to take significant amounts of mud o The total surface pumping pressure + hydrostatic pressure at the shoe= fracture pressure o Once the fracture pressure is known, the surface pressure required to break the formation for a given mud weight in the annulus can be calculated (maximum casing pressure)  𝑃𝐹𝑅 = 0.052(𝑇𝑉𝐷)(𝐹𝑟𝑎𝑐𝑡𝑢𝑟𝑒 𝑅𝑒𝑠𝑖𝑠𝑡𝑎𝑛𝑐𝑒 − 𝐴𝑛𝑛𝑢𝑙𝑎𝑟 𝑀𝑢𝑑 𝑊𝑒𝑖𝑔ℎ𝑡)

CH. 3: CAUSES OF KICKS 



Causes of kicks due to reduction in hydrostatic pressure o 𝑃𝑓@𝑇𝑉𝐷 ≥ 0.052 ∗ 𝑀𝑊 ∗ 𝑇𝑉𝐷𝑓 o Failure to keep hole full  Ex: when drill pipe is withdrawn, mud level will drop, hydrostatic pressure will drop o Swabbing- occurs when pipe is pulled and in effect creates suction  pressure changes can be minimized by:  proper mud density for formation pressure plus trip margin  minimum plastic viscosity and gel strength  careful movement of pipe when most of the pipe is in the hole o Lost circulation o Insufficient mud weight (density) o Abnormal formation pressure > expected Calculate loss of hydrostatic pressure before hole is filled when tripping o 𝑃 = 0.052 ∗ (# 𝑜𝑓 𝑠𝑡𝑎𝑛𝑑𝑠) ∗ (𝐷𝑟𝑜𝑝 𝑖𝑛 𝑓𝑙𝑢𝑖𝑑 𝑙𝑒𝑣𝑒𝑙 [𝑓𝑡])

o

𝐷𝑟𝑜𝑝 𝑖𝑛 𝑓𝑙𝑢𝑖𝑑 𝑙𝑒𝑣𝑒𝑙 [𝑓𝑡] =

𝑆𝑡𝑒𝑒𝑙 𝑉𝑜𝑙𝑢𝑚𝑒 [𝑏𝑏𝑙] 𝑏𝑏𝑙 ] 𝑓𝑡

(𝐷𝑟𝑖𝑙𝑙 𝑃𝑖𝑝𝑒 𝐶𝑎𝑝𝑎𝑐𝑖𝑡𝑦+𝐴𝑛𝑛𝑢𝑙𝑎𝑟 𝐶𝑎𝑝𝑎𝑐𝑖𝑡𝑦)[



Calculate volume required for fill up on trips (amount of mud needed to replace steel pipe) 𝐿𝑒𝑛𝑔𝑡ℎ 𝑜𝑓 𝑠𝑡𝑎𝑛𝑑 [𝑓𝑡] ( ) 𝐷𝑖𝑠𝑝𝑙𝑎𝑐𝑒𝑚𝑒𝑛𝑡 𝑔𝑎𝑙 42 [ ] 𝑏𝑏𝑙  Displacement found in Appendix A  One stand=90ft Causes of abnormal pressure o Compaction effects o Differential density effects o Fluid migration effects o Diagenetic effects-clay minerals change as buried deeper during sedimentation

o 𝑉=



CH. 4: WARNING SIGNS FOR KICKS 







Most reliable (“positive”) indicators while drilling o Increase in return flow  More mud is flowing out than is being pumped in o Pit Gain  Fluid in the hole is being displaced by formation fluid entering the well Most reliable indicator while tripping o Hole not taking required fill up  Warning sign formation fluid is entering well bore and kick is underway  Measurement of mud volumes can be made by:  Trip tank (most accurate)  Pump stroke count  Fluid meter  Pit-level change Significance of drilling break (increase in drilling rate, ROP) o Bit drills faster because of the reduction or loss of pressure overbalance o Sometimes may only indicate a change from shale to sand o Drill showo Flow check completed two times and no flow is safe to continue normal operations Significance of chlorides increase, gas- or water-cut mud o Direction of the chloride change depends on the relationship between the chloride content of the mud and the content of the formations encountered

CH.5: ABNORMAL PRESSURE DETECTION 

Normal formation pressures are in formations that have continuity through underground connections with porous formations that are exposed on the surface



 



Abnormal formation pressures are generally defined as pressures greater than those corresponding to the normal pressure gradient in a given area—usually in partially depleted formations o Believed to occur when compaction of sediments squeezes water into a more permeable formation and the fluid becomes trapped or sealed both horizontally and vertically  Total weight of sediments and water is known as overburden o This sealing action minimizes flow of fluids from the formation therefore creating excessive pressure Transition zone= area when drilling from normal into abnormal formation Parameters used for detection of abnormal pressure o ROP o Shale density change  In normal-pressured sections, density increases with depth due to compaction from the increasing overburden load. When this trend is reversed indicates over-pressured zone o Shale cutting appearance  Drill cutting have a characteristic appearance when a formation is drilled in an under pressured condition which means that the formation pressure is greater than the pressure in the drilling fluid at the face of the drill bit  Early warning sign of abnormal pressure o Mud chloride change o Flow line temperature increase o Increase of gas in mud o MWD resistivity  Normal trend: resistivity of shales increases with depth o Fill on bottom o MBT or CEC of cutting o Torque and drag o Correlation using ROP, MWD log or other trends to known transitions in offset wells Identify entrance to or increase in abnormal pressure using these parameters



Calculation of differential density effect

o



True for updip in gas sand: increase formation pore pressure gradient and increase EMW Causes of abnormal pressure o Compaction effects-rapid sediment deposition restricts pore fluids from draining during burial o Diagentic effects-tock chemistry change with time, temperature, pressure o Differential density effects  Example: gas column o Fluid migration effects- natural or man-made;

CH.7: WELL CONTROL OPERATIONS FOR SURFACE BOP STACKS 

After a possible kick is detected: o Have already done pre-kick calculations o Perform a Flow Check Perform a Hard Shut-In if flowing o Determine “Stabilized SIDPP” o Pump Start Up o Implement Driller’s method or Wait &Weight Kill

 1. 2. 3. 4. 5. 6. 7.



Flow check procedure Pick up off bottom Shut down and disengage the rotary Pick up string and space out tool joint above rig floor Turn the mud pumps off Check for flow at the bell nipple If flowing, Shut-In the well If not flowing, resume operations monitoring carefully

Hard shut-in procedure 1. Close the annular preventer 2. Open the HCR valve on choke line (be sure the choke is closed when you do this) 3. Read and record SIDPP, SICP and Pit Gain v. time in 60s increments



Interpreting “stabilized” shut-in pressures SDIPP:

o o



SIDPP will be used for calculating KWM Record pressures every 60 seconds; stop recording after 5 minutes (warning: could be longer for a tight formation) o Stabilized pressure occurs at the end of afterflow when pressures increased only steadily but slowly due to gas migration Pump start up procedure o Goals and assumptions  Need Pwell slightly > Pformation while bringing pump up to speed  Assume almost no friction in the annulus  Assume constant hydrostatic in the annulus because the kick fluids do not move fai in short time  Keep CP=SICP in order to keep Pwell constant 1. Zero the stroke counter 2. Crack the choke 3. Put the pump in gear 4. CP=SICP by opening choke as needed WHILE pump operator increases pump speed to SCR 5. Keep pump rate and CP constant until DP pressure stabilizes =ICP



Pump shut down procedure 1. Keep CP pressure constant while decreasing pump speed 2. Slam choke COMPLETELY CLOSED when pumps are off







Killing a well is done by maintaining a constant BHP>FORMATION PRESSURE o Achieved by 3 things: 1. Pump rate 2. Pressure 3. Mud Weight Driller’s method & calculations o Hold constant drillpipe pressure o Average MW in annulus is not constant (due to expanding gas kick) o Cannot use casing pressure to maintain BHP o Must use constant pump rate and mud weight to maintain constant BHP o Casing pressure cannot be held constant to maintain a constant BHP because the mud weight is changing in the annulus o When pumping KWM down drillpipe:  Hold casing pressure constant (no kick in the well annulus anymore)  Cannot hold drillpipe pressure because the average MW in the drillpipe is not constant due to MW, pump rate and constant pressure in the annulus. This will hold a constant BHP. o Calculate KWM. o Advantage: start pumping kick out immediately

Wait and weight method calculations (kill sheet) o CONSTANT BHP > FORMATION PRESSURE o Perform all calculations on kill sheet o Control BHP is kick is gas by OCCASIONALLY bleeding mud through the choke to keep DPP constant as the gas migrates o When active pits are at kill mud weight, zero the stroke counter o Pump start up procedure

o

 

Follow the drillpipe schedule to compensate for the hydrostatic gained and additional frictional pressure loss due to the KWM replacing the original MW  Stop when KWM reaches the bit o Once DP is filled with KWM, keep the DPP at FCP (final circulating pressure) and the pump rate constant to maintain BHP until KWM reaches the surface o When circulating out a kick—KWM is going down DP and kick is in the annulus  Cannot hold DPP constant because the MW is changing  Must follow table from kill sheet  Cannot hold CP constant because the mud weight in the annulus is changing due to gas expansion  Must follow table from kill sheet o When circulating out a kick:  You are pumping KWM up annulus  Must hold FCP constant  Casing pressure cannot be held constant because the MW is changing due to gas expansion in the annulus o When KWM reaches the surface:  Shut down the pump  Close the choke  Check for SIDPP and SICP  If >0 bleed a small volume through the choke and recheck  If Pressures=0, open the choke to bleed any trapped pressure  Open BOP and check for flow o After kill, circulate to add TRIP MARGIN to KWM  ~200-300psi overbalance o Advantage:  Lower maximum casing pressure  Less circulation time required  Calculations useful for predictions of driller’s method If BHP
CH.10: ON BOTTOM WELL COMPLICATIONS

Plugged Bit (nozzle) Washed Out Bit (nozzle) Plugged Choke Washed Out Choke 





 

Drill Pipe Pressure INCREASE DECREASE INCREASE DECREASE

Casing Pressure NO CHANGE INCREASE INCREASE DECREASE

Surface equipment problems o Plugged choke  Detected by rise in BOTH drill pipe and casing pressure o Cut-out choke or choke manifold  Detected by decrease in drill pipe pressure and casing pressure cannot corrected by choke manipulation  Reroute to standby choke o Pump problem  Employ stand-by pump o Leak in BOP stack o As soon as a problem with the surface equipment is suspected, the pump should be stopped immediately and the well closed carefully so as not to trap any pressure created by the pump Subsurface well problems o Plugged bit  Detected by sudden increase in drill pipe pressure without corresponding increase in casing pressure  Sudden decrease in drill pipe pressure may indicate plug is breaking free o Bit nozzle washout  Detected by sudden decrease in drill pipe pressure without corresponding decrease in casing pressure o Hole in the drillstring  Detected at the surface by a rapid decrease in drill pipe pressure without a corresponding decrease in casing pressure o Borehole fracture, cement failure or casing failure Excessive well pressures o When large volumes of low-density kick fluid displaces mud from the annulus, excessive casing pressure can result o If kick fluids displace mud from the drill string, excessive drill pipe pressure can result How to control pressures during gas migration while the well is shut in o Must be controlled How to correct action to take any time during a kick circulation that pressures and/or other indicators are different than expected

Ch. 12: Well Control Operations for Subsea BOP Stacks  



The increase in water depth between the BO equipment and the floating drilling vessel adds several complications to the problem of well control Early Kick Detection o When pulling out of hole the primary warning is a hole fill-up volume less than the volume of steel removed from the hole o Most common indicators:  Increase in flow rate from well  Gain in pit volume  Change in drill pipe pressure  Increase in pump rate  Increase in rate of penetration  Pressure shale cuttings  Increase in concentration of gas in mud  Increase in flow line temperature o Motion of a floating vessel interferes with the observations of an increased flow from the well or a gain in pit volume—the most important warning signs  pitch and roll of the drilling vessel leads to the formation of waves in the mud pits, causing fluctuations in pit level indicator  partially solved by using baffled pits and using several pit indicators in each pit in conjunction with a pit volume totalizing computer  the heave (vertical movement) results in elongation and contraction of the marine riser causing the flow rate from the well to also fluctuate Well Control Procedures o Having the BOP stack on the sea floor requires THREE changes to well control procedures 1. When it shutting in the well the drill pipe may be hung off on one of the subsea pipe rams 2. Pump start-up procedure must compensate for the additional friction created by the return mud flow through the long underwater choke line 3. If a gas kick is being circulated from the well a severe operational problem can result when the gas bubble reaches the subsea BOP stack



Subsea Well Control Equipment o At the well head connector:  3 pipe rams: blind/shear ram, annular preventer, and a second annular preventer  The second annular preventer is attached to the bottom of the riser package which allows a safe re-entry into a shut-in well  The choke line is located just above the lower pipe rams to accommodate high pressure flow from the well  The kill line is connected just below the shear rams so that mud can be pumped into the well if the drill string were sheared  Can serve as an additional choke line  Situated around the riser tube is six other high pressure lines  2 for choke and kill lines  Other 4 are for air and hydraulic fluids



Pre-kick Information o Casing data and maximum allowable choke pressure  Consideration must be given to the effect of hydrostatic pressure created by the drilling mud in the choke line and the water depth 𝑴𝒂𝒙 𝒄𝒉𝒐𝒌𝒆 𝑷 = [𝟎. 𝟕𝟎 ∗ 𝑩𝒖𝒓𝒔𝒕 𝑷𝒓𝒆𝒔𝒔𝒖𝒓𝒆] − [. 𝟎𝟓𝟐 ∗ 𝑹𝑫𝑭 ∗ 𝑴𝑾] + [. 𝟎𝟓𝟐 ∗ 𝑾𝒂𝒕𝒆𝒓 𝑫𝒆𝒑𝒕𝒉 ∗ 𝟖. 𝟓]

 



Maximum allowable choke pressure applies only when the well is shut-in When the well is being circulated this maximum pressure limit will have to be reduced by an amount equal to the frictional pressure associated with mud circulation through the long under water choke

Capacity Factors o Two additional capacity factors are called for: choke line and drill pipe riser annulus  Needed when calculating total volume of active mud system and time required to displace choke line volume  Choke line: D2/1029.4  Drill pipe riser annulus: 1. ID=OD-(2*Well thickness)









2. Capacity annulus= difference of capacity factors Mud Pump Displacement Factor o High efficiencyassume 100% efficiency to simplify calculations o How to check pump efficiency  Can be measured periodically  Calculated “perfect” pump strokes compared to the actual strokes  As the driller is making a connection the pump suction can be switched to a small easily metered tank (trip tank) and stroke counter zeroed o With bit on bottom, pump output as determined from the drop in mud level is compared with the total strokes pumped o Advantages  Pump is working against normal circulation pressures  Procedure does not interrupt normal drilling operations Measurement of Choke Line Friction o Reduced circulation rates are chosen to represent the slow pump-out rate (kill rate) that could be used in the event of a well kick o Rule-of-thumb: choose a kill rate that results in an annular velocity (in the largest part) in the range on 40-50ft/min 𝑏𝑏𝑙 = 𝑆𝑃𝑀 ∗ 𝑃𝑢𝑚𝑝 𝐹𝑎𝑐𝑡𝑜𝑟 𝑚𝑖𝑛 𝑏𝑏𝑙/𝑚𝑖𝑛 𝐴𝑛𝑛𝑢𝑙𝑎𝑟 𝑉𝑒𝑙𝑜𝑐𝑖𝑡𝑦 (𝐴𝑉) = 𝐴𝑛𝑛𝑢𝑙𝑢𝑠 𝐶𝑎𝑝𝑎𝑐𝑖𝑡𝑦 o Frictional flow losses in the system associated with the mud flow through the:  Drill pipe  Drill collars  Jet nozzles of the bit  Open hole drill collar annulus  Open hole drill pipe annulus  Casing drill pipe annulus  Marine riser drill pipe annulus o Major part of the reduced circulation pressure is used to maintain the flow through the drill string and bit o Choke line friction is important!!!! Mud Volume in System o Once the stabilized pressures, pit gain, and present mud weight are recordedKWM Pump Strokes and Pumping Times o Number of pump strokes required to circulate KWM to bit—important!! o The calculation gives the maximum number of strokes required to displace the kick fluid up the choke line—the kick fluid will reach the sea floor ahead of the bottoms o Last calculation provides an estimate of the strokes required to pump the top of the kick fluid from the well bottom to the point where it enters the choke line

   



Final Circulating Drill Pipe Pressure o Needs only to be sufficient to overcome the flow friction in the drill strong and bit Total Drill Pipe Pressure Reduction o Made to drop in keeping with the advance of KWM down the drill pipe Pressure Drop per Step o Stepwise procedure is identical to that used for a surface BOP stack Pump Start-Up Procedure o When the pump is initially being brought up to speed the required drill pipe pressure is unknown since the circulating pressures at those changing rates are unknown o Hold the casing pressure constant at a value equal to its shut-in value  The choke is opened as the pump is brought up to speed in such a way that the casing pressure remains constant at its shut-in value while building up to desired kill rate  if this approach is attempted in deep water (>300ft) there is a good possibility the well bore will fracture at the casing seat o The additional back pressure on all points in the well bore is the sum of these two pressures: 1. the flow friction to be overcome in the choke line 2. the pressure required to force fluid through surface choke o To avoid any problems, the pump state-up procedure must provide for the original shut-in casing pressure to be dropped in step with the increasing pressure being developed by the flow friction in the choke line o As the pump nears its final rate, reduce the surface choke pressure by an equal amount to the back pressure created from choke line friction when the pump is shut down (0 spm) the choke pressure will be at its shut-in value o The pump start-up schedule is valid only if the length of any gas zone in the annulus does not change significantly during start-up Gas Bubble Pump-out o One possible trouble is the ability to control the choke properly as a gas kick is circulated up the annulus and begins entering the choke line o The gas will displace the mudthe hydrostatic pressure of the previous mud column along with the flow friction will be almost eliminated o This loss in back pressure must be compensated for by a rapid reduction in the choke opening o Failure to react to the rapid changing pressure conditions will allow an additional influx into the well o As the bottom of the gas bubble reaches the choke line, the situation is reversed  Choke line will again become filled with mud





Now the hydrostatic pressure and flow friction of a full mud column will be applied to the annulus  Choke operator must quickly compensate for effects by reducing the pressure drop across the choke  If fail to reduce pressure underground BO is likely to occur o To reduce the severity of the problem:  Use a slower pump rate  Make use of a larger ID choke line  Smaller ID, shorter time available to control pressures  Both o Adding an additional line in parallel allows for the benefits of a slower pump rate (slower purge time and reduced flow friction) without having to extend the total well circulation Excessive Choke Line Friction o Trouble source when end of kill or when first starting to pump o When the line is filled with KWM it is no longer necessary to maintain any back pressure on the annulus  With the choke wide open the flow friction in the line will still provide back pressure in excess of the original choke line friction  This represents a needless back pressure on all portions of the hole o During the initial start-up of the pump after a kick, the casing seat is likely to be subjected to an unnecessary pressure increase and possibly a formation break down at the shoe  Only alternative is to choose a slower pump-out rate

CH.13: Workover and Completions Operations o o

o

Maintaining control of a well during the completion and workover phases is oftentimes more complicated than well control in drilling operations Complications:  Several different rig systems being used on a single workover or completions/recompletion  Various types of workover fluids being used ranging from low density nitrogen to high density brine fluids or packer fluid systems  Many interrelated activities being simultaneously occurring such as workovers on a platform with producing wells and corresponding production equipment Reasons for workover and completion/recompletion operations:  Reworking the producing reservoir  Completing a new reservoir  Completing multiple reservoirs  Stimulating existing reservoirs to increase production





 Repairing mechanical problems that reduce or prevent production Multiple Completions o Ex: producing multiple zones at once o Zones are produced separately because of regulatory requirements or because they are incompatible  Incompatibility could be due to the type of production or different reservoir drive mechanisms  Ex: production from a gas zone with the production from a dead oil zone  If the dead oil zone loses BHP faster than the gas zone the gas would migrate in to the dead oil zone, called “thief”, creating a new and possibly different level of hazard potential  Zones that are incompatible are best kept isolated from eath other  If leaks occur, a high pressure zone near its original pressure could fracture a zone whose bottom hole pressure has declined significantlyunderground BO  A pill can be used to protect the weaker zone Small Tubular Operations o Reduce the resistance to torsonial forces o Operations are near the surface o Slimhole drilling is a specialized type of small tubular drilling operation that offers economic benefits—completion tubulars cost less, small rigs can be used to drill the same depth hole  Problems: more twist-offs created because of the lower torsional strength of the pipe and high frictional pressure losses o Workover and completion operations that use small tubulars:  Snubbing  Differs from coiled tubing operations in that joints of threaded pipe are used instead of a continuous reel or coil of tubing  Snubbing units have the capability to rotate their entire tubular string while coiled tubing units must rely on a downhole motor  Snubbing operation involved moving slips to force pipe into the hole against pressure  Can be used to drill out sand bridges inside tubing or can be used to run or pull tubing as an alternative to a conventional workover rig  Hazards of snubbing: o Surface equipment is exposed to pressure continuously o The tubing could be ejected from the well if an equipment failure occurs o Snubbing units are slower than conventional workover rigs  Coiled tubing operations  Used to economically wash out sand bridges or to inject gas to “kick-off” a well that has stopping flowing

  







Chemical treatments can also be pumped through coiled tubing Coiled tubing can be forced into a well using an injector head Hazards: o Same as snubbing o Coiled tubing walls are thing with a limited resistance to collapse and twisting Small tubing operations  Problems: o Frictional pressure losses during circulation will be high o Clearances are tight so it is easier to get stuck and harder to fish o The smaller tubing strings have less tensile strength and limited resistance to twisting

Perforating o Perforating operation that opens the zone to be produced to the production tubulars o Usually done with shaped charges that blow a hole through the casing cement into the formation o Older technique: use a hard metal bullet to accomplish the same thing o Perforating guns may be run on the end of tubing or run on wireline  Wireline guns are reusable o Perforating may be done inside casing only or a small diameter gun can drop through tubing and perforate the casing o High pressure lubrication is usd to seal around the wireline o Measures used to handle electronically detonated high explosives must be used o Unconsolidated sands may flow into the tubing after perforation trapping the pressure beneath one or more plugs of sand  Limiting the pressure differential into the wellbore might prevent this problem Drill Stem Testing o Drill-stem testing is a temporary completion of a well while the drilling rig is on location before either production casing or tubing have been run o Drill pipe is used to replace tubing and a packer is used to provide the isolation zones o Hookwall test-a test performed inside casing o To obtain information about a zone’s productivity it is necessary to flow the zone into the drillpipe  The rate of pressure build up is recorded  From this we can calculate the productive capability of the zone o Safety considerations:  If anticipated high flow rates, approx. sized downhole choke should be used in the test string  H2S hazards  Surface equipment must be of adequate rating to handle shut-in pressures during test



Miscellaneous Completion Operations o Swabbing  Usually done inside tubing  Swab cup is similar to an old-fashioned schoolyard pump  Check valve allows fluid to pass through the cup while it is traveling down. When the cup is pulled back up the check valve seats and the swab cup acts like a piston and lifts fluid to the surface  Hazard: a dead well can suddenly become live o Bridge plug setting  Sometimes set on wireline in casing  Main problem: no tubulars are in the hole to use for circulation o Plug setting  Set in tubing inside landing nipples  Plug is used to isolate a zone  If a plug has no pressure equalizing feature then it can be blown uphole by a pressure differential o Safety valve setting  Should have an equalizing feature to prevent damage to the valve o Many more…