This papers is a elaborate good be aftering papers for the SW-P02 good designed to be a manufacturer. It is to be drilled as a manufacturer good with a build-and-hold or J profile. The inclined subdivision was built with a dogleg badness of 3o/100 foot at a kick-0ff point of 1500 foot TVD to an end-of-build angle of 36.86o and an AZ of 90.92o. The tangent flight is so held to a Entire deepness of 10250 ft TVD.
The design computations for the shell led to a pick of two casing classs from Vallourec and Manesmann cache of tubing. These were the L80 53.5 lb/ft and the C110 53.5 lb/ft. The shell was besides cemented with two slurries, 14.2ppg lead slurries with the top of cement at 5200 foot TVD ( 5291 foot MD BML ) . The Tail slurry was besides designed to be 15.8 ppg with top of tail at 7900 foot TVD ( 7900 foot MD BML ) . A sum of 11,300 gals of mix H2O and 140,000 pound of G orderly cement is used.
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For the rating of the over-pressured shales, Resistivity, Gamma beam and Density neutron logs would be run utilizing LWD tools. A positive show of the likely presence of hydrocarbons would so ensue in the running of a wireline suite of a unstable sampling station such as the Modular dynamic proving tool ( MDT ) and a side-well nucleus would be taken for analysis utilizing the Mechanical side-wall Coring tool ( MSCT ) .
The well would be completed as a individual zone completion of the primary mark. This would be done utilizing a pierced cased-hole design with crushed rock wadding and a wire wrap screen installed on the underside of the production tube. It besides proposed that should the over-pressured zone brush hydrocarbons, so a new good be drilled aiming that zone from another slot and completed as a new manufacturer.
2.1 WELL INFORMATION
The SW-P02 well is scheduled to be a manufacturer in the Soggy Wetland field operated by Large State Oil Company. A 26 ” music director shell was installed when the basement was constructed and a 18 5/8 ” , 96.5lb/ft, J55 surface shell is to be set at +/- 1200 foot.
It is anticipated that the well would stop some H2O wet sands believed to be permeable and susceptible to fluid losingss ( between 3,300ft and 3,800ft ) . A salt formation is to be encountered between 5,300ft and 8,000ft that would necessitate an addition in mud weight to forestall motion. There is an over-pressured zone from 8,300ft to 9,200ft which may incorporate hydrocarbon bearing sand and would be evaluated as a secondary mark.
The primary reservoir mark is the littorals between 9,600ft and 9,900ft which is of good permeableness.
An 8 A? ” hole is planned to be drilled through the reservoir and logged to the well TD proposed to be +/- 10250ft TVD. A speed study will be shot before the reservoir is cased away and completed to better specify the reservoir.
Design OF WELLBORE TRAJECTORY
The pick of a wellbore flight is informed by the supplanting between the boring Centres and the mark zones, wellbore disposition through mark zone to maximize productiveness, type of completions and perchance the available engineering.
3.1 GEOMETRICAL WELL PLAN
The SW-P02 well will be directionally drilled with the build-and-hold profile. It would be kicked off at 1500 foot TVD BML. This is to let for the intersection of the mark at an disposition, giving more footage in footings of exposed reservoir country, comparative to a perpendicular attack through the reservoir. ( i.e. utilizing the S-type profile ) . Below are the computations involved in the planned wellbore flight. This would besides hold be selected in order to avoid hit with environing Wellss.
Figure 3.1: Proposed planned profile of the SW-P02 well
3.2 CALCULATION OF WELLBORE GEOMETRY DETAILS ( DEPARTURE, AZIMUTH AND INCLINATION )
Table 3.1: Summary of partial northings and easting computation
To cipher going ( grid supplanting ) we apply the expression below:
Converting the distance D3 to pess and using the UTM Scale factor at the cardinal Meridian, 0.9996. ( Geokov.com, 2013 ) We have:
D2= ( 1731.23 x 3.28084 ) / 0.9996 =5682.1615 foot
Calculating the AZ we use the expression:
I‰=Tan-1 ( 62.14o )
Therefore the AZ would be 360o- I‰o, since by their partial co-ordinates it can be found in the 4th quarter-circle.
AZIMUTH= 180o- 89.08o=90.92o
Figure 3.2: Plan position of good supplanting, demoing the AZ
The KOP ( V1 ) is at 4600ft TVD and a build-up-rate ( BUR ) of 3o/ 100ft is used. To cipher the build- up radius we used the expression
Finding Angle I©
Finding Angle I?
But BE is given as
Therefore replacing the value of BE, we have:
We so find the angle O =Angle I? + Angle a„¦
Angle O =12.07+ 24.79o
To happen TVD supplanting at end-of-build=
Hence TVD at terminal of build =1500 foot +1145.65 foot =2645.6516 foot
Therefore going at end-of-build, D1= R1 ( 1-Cos O )
D1=GF= 1909.8593 ( 1- Cos 36.86 )
D1 =381.7739 foot
The measured deepness at end-of-build would so be:
Therefor MD from mud-line to end-of-build = 1500ft +1274.67 foot =2728.67 foot
To happen the mensural deepness at mark we use the expression below:
Therefore the measured deepness at the top-of-target = 2728.67+8728.681ft =11457.35ft
Measured Depth, MD
True Vertical Depth, TVD
( Degrees )
( Degrees )
Kick off Point
Table 3.2: Drumhead tabular array of points on the well flight
Figure 3.3: Well plot location record
Table 3.3: Summary of good secret plan location
4.0 CASING DESIGN PROGRAM
Casing design plan involves the choice of puting deepnesss, sizes and classs of steel required for safe boring and completions of a well. These design demands are nevertheless affected by a figure of factors such as lithological conditions, the needed production tubing size, down-hole force per unit areas ( Pore and break Pressures ) , temperature profile, fluids nowadays ( i.e. Oil, gas, H2S or CO2 ) , good head equipment size etc. the attack is nevertheless to take the most economical way that can acquire the occupation done and must besides be designed along the idea of handiness.
( TVD )
26 ” Conductor
The shell was installed when the basement was constructed and would supply support to the unconsolidated formation.
+/- 1200 foot
18 5/8 ” Surface casing
An 18 5/8 ” , 96.5lb/ft, J55 casing would be set as surface shell. This would supply structural support for the shell and keep the High force per unit area wellhead lodging. It would besides supply isolation of fresh H2O formation.
17 A? ”
13 3/8 ” Intermediate shell
A 13 3/8 ” , 72 lb/ft, L80 VAM is scheduled to be set at 4200ft TVD BML. This is because the shales would supply a amalgamate formation for puting the casing shoe. It is besides the point where the pore force per unit area bit by bit starts to alter. The pick of the shale would besides function as a amalgamate formation in which we get a good tangent for dropping off the well to aim.
12 1/4 ”
9 5/8 ” Production Casing
A 9 5/8 ” , 53.5 lb/ft, L80 and C110, 53.5 lb/ft shell would be set at a deepness of 9500ft TVD BML. This would let for a 100ft above the mark reservoir zone. It would give equal room for LOT/FIT before come ining the reservoir zone. At this point the pore force per unit area of the reservoir besides drops and this would let for decrease of the clay weight of the boring clay to provide for this force per unit area anomalousness
8 A? ”
7 ” Liner
A 7 ” , 42.59 lb/ft, L80 VAM production line drive would be set at +/- 10250 MD, 350 foot MD below the reservoir mark zone, to let for a sump and adequate deepness for the running of logging and completions tools such as TCP guns which are usually dropped in the wellbore after firing.
4.1 PRODUCTION CASING DESIGN ( 9 5/8 ” )
The production is exposed to forces such as explosion and prostration force per unit areas with tenseness besides moving on the twine. These forces should hence be calculated as portion of the design procedure in order to guarantee that the shell can defy all these forces.
4.1.1 Burst design
The design of the 9 5/8 ” shell is based on the premise of the worst instance state of affairs of where the boring clay is to the full evacuated in the event of a heavy boot thereby the shell is to the full filled with gas. In order to make the explosion calculations the undermentioned premises are made ( Rabia 2008, p114 )
Gas gradient: 0.15 psi/ft
The burst force per unit area is highest at the shoe and is tantamount to formation break gradient with a safety border of 0.5 ppg.
Design factor of 1.1
Formation pore force per unit area gradient is 0.45 psi/ft
The burst pressure=Internal force per unit area – external force per unit area
At the casing shoe, the internal force per unit area is assumed to be the break force per unit area plus a safety border of 0.5 ppg.
The clay weight used in the 9 5/8 ” casing subdivision is 13.8 ppg, therefore the internal force per unit area can be calculated as:
Internal pressure=7064.2 pounds per square inch
The external pressure= ( formation force per unit area gradient ) x TVD
External Pressure= 0.465 psi/ft x 9500= 4417.5 pounds per square inch
Burst Pressure= ( internal force per unit area ) – ( external force per unit area )
Burst Pressure=7064.2-4417.5= 2646.7 pounds per square inch
At Surface the internal experienced is the difference between the hydrostatic of the clay and the force per unit area gradient due to the inflow of gas.
Internal Pressure = Hydrostatic – ( TVD x gas gradient )
Internal Pressure = 7064.2 – ( 9500 x 0.12psi/ft )
Internal force per unit area =5924.2 pounds per square inch
External force per unit area is nevertheless considered to be zero, because it is unfastened to the ambiance.
At surface, Burst pressure=5924.2 – 0 pounds per square inch = 5924.2psi
Factoring in the safety factor, Burst as surface= 5924.2 ten 1.1= 6516.6psi
Internal force per unit area, pounds per square inch
External Pressure, pounds per square inch
Resultant, pounds per square inch
Attendant design explosion x ( Df=1.1 )
Table 4.1: Summary of explosion force per unit areas
4.1.2 Collapse Pressure Design
The prostration force per unit area is done on the footing of the premise that the shell is in the improbable state of affairs of being wholly empty and the ring is filled with clay or cement.
Figure 4.1: Sketch of the prostration of casing due to external fluid force per unit area
Collapse force per unit area at surface:
Collapse force per unit area at surface= External force per unit area – Internal force per unit area
But at surface the shell is exposed to atmospheric force per unit area both on the interior and outside so collapse force per unit area at surface is zero.
Collapse force per unit area at Shoe:
Since the pick of cement denseness is more than that of the clay denseness used in boring the well, all external burden is calculated utilizing the clay weight of the cement.
The internal force per unit area is zero, because entire emptying of internal clay has been assumed.
External pressure= Hydrostatic of lead cement + Hydrostatic force per unit area of Tail cement+ hydrostatic force per unit area of clay above the cement.
Hence: Hydrostatic pressure= Mud weight x 0.052 x TVD
Hydrostatic of Mud column = 13.6 ten 0.052 ten 5200 = 3677.4psi
Hydrostatic of Lead cement =14.2 x 0.052 ten ( 7904 -5200 ) = 1996.6 pounds per square inch
Hydrostatic of Tail cement =15.8 x 0.052 ten ( 9500-7904 ) = 1311.3 pounds per square inch
External Pressure= 3677.4+1996.6+1311.3 =6985.3 pounds per square inch
Using design factor of 1.1 ( 10 % surplus ) , we have:
=6985.3 x 1.1=7683.8 pounds per square inch
External force per unit areas psi
Internal force per unit areas psi
Attendant pounds per square inch
Designed prostration force per unit area, Df=1.1 pounds per square inch
Table 4.2: Drumhead tabular array for Collapse burden computations
Since in this instance the prostration force per unit area is higher than the explosion burden, a pick of casing should hold a evaluation more than 7700psi about. From the Vallourec and Manesmann Tubes catalog, a C110 shell was chosen. Below are the inside informations of the shell:
Collapse Press Rating
9 5/8 ”
53.5 ( lb/ft )
0.545 ( in )
6620 pounds per square inch
9 5/8 ”
53.5 ( lb/ft )
0.545 ( in )
7950 pounds per square inch
Table 4.3: Selected casing specification
Figure 4.2: Collapse and explosion lines
4.1.3 Tensile Design
The entire tensional burden at any clip is the amount of forces such as:
The weight in air of casing
Drag or daze burden ( depending on which is greater )
Casing trial force per unit areas ( BG Group, 2001 )
MW= Mud weight of boring fluid
( lb/ft )
Air weight of Section
( lbf )
Air Wt of Top Joint
Buoyant Wt X
( 1+2+3 )
( Yield strength ) /TTL
53.5 ten 3000
3200x 53.5= 171,200
53.5 ten ( 11195-3000 )
3200x 53.5= 171,200
Table 4.4: Selected casing tensional strength specification
Bending force= 63 ten WN x OD x I?
Where WN= Weight of casing per pes
OD= Outer diameter of casing
I? = Dogleg badness, degree/100 foot
Maximum Shock Loading= 3200 x WN
CEMENTING PROGRAMME FOR PRODUCTION CASING
The primary maps of cement are to supply zonary isolation, back up the axial tonss of casing strings, protects casing against caustic fluids and back up the wellbore ( Rabia 2008 ) .
The cement used in the industry is manufactured to API Specifiation10 and comes in eight categories, viz. A, B, C, D, E, F, G and H. Classes G and H are nevertheless the most used in the industry because they mix easy with additives to cover a scope of deepnesss and temperatures. Class G cement is used in this instance.
Class G cement is chosen for this occupation because it has a broad scope of deepness and screens high force per unit areas and temperatures ( Bourgoyne et al, 1986 ) . Its authority nevertheless is dependent on the add-on of additives such as gas pedals and/or retarders.
5.1 CEMENT TOPS LOCATIONS
Height of cement in the ring would hold a corresponding hydrostatic force per unit area. This column of cement based on its clay weight should non transcend the prostration force per unit area evaluation of the set shell and should non fracture the formation. The cement tops are besides informed by the type of petrology being drilled through.
Therefore cement slurries are design such that the attendant hydrostatic force per unit area takes into consideration the above factors.
The top-of-cement for the 9 5/8 ” production shell is to be located at 5200 foot TVD/5921ft MD, 200 foot above the salt zone. The base is design to give allowance for 30ft of rat hole the cement shoe is hence at 9500ft TVD or 1111270 ft MD. An surplus of 25 % is assumed to counterbalance for hole enlargements in the computation of cement slurry volumes.
5.2 CEMENT VOLUME REQUIREMENT CALCULATIONS
Figure 5.1: Schematic of 9 5/8 ” casing cementing programme
The cement volumes are calculated in phases:
Open hole: 12 A? ”
Casing OD: 9 5/8 ”
5.2.1 Tail Slurry Properties
The tail slurry is designed non to transcend the fracture gradient at the shoe, 17.2 ppg upper limit. Therefore it is designed to be 15.8 ppg upper limit. The top of the tail slurry is set to cover the over pressured zone to 9300 foot MD/ 7900 foot TVD.
5.2.2 Lead Slurry Properties
The Lead slurry was besides designed non to transcend the fracture gradient at the shoe, 15.2 ppg upper limit. Therefore it is designed to be 14.2 ppg upper limit. The top of the tail slurry is set to cover the over pressured zone to 9300 foot MD/ 7900 foot TVD.
The Annular capacities would so be calculated as follows:
12.25 ” Open hole and 9.625 ” Casing Lead cement
Annular capacity, V1
With an surplus of 25 % = 166.8*1.25 = 333.6 barrel ( Approximately 337 barrel )
This can be calculated in three-dimensional pess as = 337 ten 5.614 =1892
Assuming a output factor of 1.5
5.2.3 Cement Volume Calculations
12.25 ” Open hole and 9.625 ” Casing Tail cement
With an surplus of 25 % = 27.9*1.25 = 35 barrel
Volume of tail cement in 12.25 ” rat hole:
With an surplus of 25 % = 5 ten 1.25 = 6.25 barrel ( Approximately 7 barrel )
Volume of tail cement in 9.635 ” shoe path:
Approximately 3 barrels
Hence entire cement slurry required =3 +7 +35=45 barrel
But 1 barrel =5.614 ft3 hence we have: 45 x 5.614 =253 ft3
Assuming a output factor of 1.15
So entire poke demand = 220 +1262 =1482 poke
But dry weight per poke is 94 lb hence for 1482 pokes, entire weight
=1482 x 94=139,308 pound ( about: 140,000lbs )
Volume of assorted H2O required =Number of pokes ten H2O required per poke
Water required per poke = 7.6 gal/ poke
Volume of assorted H2O required =1482 sk x 7.6 gal/sk
Volume of assorted H2O required =11,263.2 gal ( about: 11300 gal )
Converting to cubic pess = ( 11263.2/42 ) x 5.614 ft3
Volume of assorted H2O required =1506 ft3
Figure 5.2: Casing puting deepness based on pore and break force per unit areas
Figure 5.3: Summary of casing and cementing programme
Well SURVEY PROGRAMME
The well being drilled from a slot should be surveyed during and after boring. The aim of this is to guarantee that:
Anti-collisions studies are run so that the well is non placed in such a manner that it would clash with environing Wellss.
To find the exact location of the well while boring in order to rectify dog-leg-severity thereby guaranting that we hit our mark.
The well bore flight in documented. This would guarantee that subsequent Wellss being planned would be done being good cognizant of environing Wellss and for future side-tracking activities.
To make this Measurement-While-Drilling ( MWD ) tools and Gyros will be used. The
MWD appraising engineering is used to specify the well way and its place in 3-dimensional infinite. It helps set up the true perpendicular deepness, bottom hole location and the orientation of wellbore.
Gyros are tools comparable to MWD tools and are used in the measuring of the dip of a well. It is alone because it is unaffected by magnetic intervention that occur as a consequence of the intimacy of steal constituent. It comes ready to hand particularly when boring top hole subdivisions from slots, because the spot so is even closer to other Wellss.
There will be no study runs during the installing of the 26 ” shell
An MWD tool would be used to study the well every 90ft ( every base ) . This would inform us about the verticalness of the well since it would be in close scope to other good when it is being drilled from a slot.
17 A? ”
An MWD and GWD tool would be used in this subdivision. The usage of a combination of the two is of import because we would kick off the well in this subdivision and would necessitate high truth in mensurating the disposition, AZ and the overall dogleg badness. A study would besides be taken every 90 foot.
12 A? ”
An MWD and GWD tool would be used in this subdivision. A study would besides be taken every 90 foot. This is necessary because although the curving subdivision has been drilled, it is of import to maintain the tangent else we may lose our mark by traveling below or TD the well above the reservoir.
8 A? ”
An MWD and GWD tool would be used in this subdivision. This would guarantee that maintain the well way through the reservoir.
Table 6.1: Summary of study programme
MANAGEMENT AND EVALUATION OF THE OVER-PRESSURED ZONE
The over-pressured zone contains petrology such as limestone and shales and a small spot of shales inter-bedded with littorals. The petrology that would hold the most negative consequence on the wellbore is the over-pressured shales. This may take to hole instability. The hole instability may be characterised by under-gauge hole, over-sized hole inordinate volumes of film editings returns to come up etc.
This phenomenon is nevertheless combated by utilizing a higher clay denseness or increasing the equivalent go arounding denseness ( ECD ) which is normally most of import in finding whether an unfastened hole is stable. It will be necessary to work within the clay window of pore and break force per unit areas. To remain within this scope wiper trips may be required for hole cleansing so we do non enforce a hydrostatic higher than the break force per unit area. Concentrate force per unit area Engineers would besides be hired to foretell the over-pressured zone.
In measuring the formation Loging while boring tools would be employed to mensurate the electric resistance, gamma beam and denseness neutron logs. If consequences show marks of the presence of hydrocarbons, so a wireline suite would be run with the Modular dynamic examiner ( MDT ) tool and a Mechanical Side-well coring tool ( MSCT ) would be taken for analysis.
The production casing prevarications in the inclined subdivision of the SW-P02 well. The boot of point is 1500ft TVD with a dogleg badness of 3o/ 100ft. The tangent was held at 36.8o at the end-of-build at a deepness of 2728 foot MD ( 2646 foot TVD BML ) .
As an inclined well, the BHA is designed bearing in head the disposition of the wellbore and the attendant weight on spot ( WOB ) required in accomplishing good footage. The proposed drill threading for the production subdivision is given below:
12 A? ” PDC Bit
Rotary Steerable System ( RSS )
Non-Magnetic drill neckbands ( NMDC )
Non-Magnetic drill neckbands
Spiral Drill neckbands
Heavy weight drill pipe ( HWDP )
Maximal weight on spot is ( WOB ) = 25000 pound
Safety border is 10 %
Overpull scope 50,000 to 100,000 pounds ( Rabiaaˆ¦ . )
Drill collar OD is 8 ” ( Rabia, 1995 )
5 ” HWDP Range 2 is used
Weight of MWD 3400 pound and weight of Jar 3000lbs ( slb BHA Catalog )
Number of coiling drill neckbands: 5
Number of Non Magnetic drill collars:2
Hole deepness = 11420ft
Hole size = 12 A? ”
Mud weight = 13.6ppg
Safety Margin ( SM ) = 10 %
Inclination, I? = 36.86o
Estimate of figure of HWDP
Air weight of BHA and length of BHA is given in API RP 7G as
Air weight of BHA
Entire BHA weight in air = 43835.5
Required BHA air weight=43835.5lb about 43900 pounds
HWDP weight= BHA Weight- ( 2xNMDC+3x Spiral DC +Jar Wt + MWD Wt + LWD + 2 x Stabilizer )
From API RP 7G, weight of 8 ” OD Drill Collars is = 150 lb/ft
Assuming 5 % weight decrease, effectual weight of 8 ” OD spiral drill neckbands will be = 0.95 ten 150 =142.5lb/ft
So, for 6 articulations of 8 ” OD, 31ft long spiral drill neckbands, entire weight will be = 142.5 ten 3 ten 31 =13,252.5 pound
Weight of two NMDC: 2 x 150 ten 31 lb= 9300 pound
Weight of MWD: 3400 pound
Weight of LWD: 2800 pound
Weight of Jar: 3000 pound
Weight of 2 Stabilizers: 1200 pound
HWDP weight= 43900- ( 9300+13253+3000+ 3400 + 2800 +1200 ) = 11,347 pound
A 5 ” HWDP weighs 73.4 kg/m =49.3 lb/ foot
Therefore the length of 5 ” HWDP required=
The mean length of HWDP is 30 ft hence the entire figure of drill pipes is:
Approximately 8 articulations of HWDP are required.
Entire Length of BHA = Length of HWDP + Length of DC
Entire Length of BHA = 231 + ( 8 x31 ) =479 foot
New BHA air weight = ( 9300+13253+3000+ 3400 + 2800 +1200 ) + ( 8 x31x49.3 ) = 45,179.4 pound about 45200 pounds
8.1 CALCULATION OF NEUTRAL POINT
Calculating for the impersonal point is relevant in make up one’s minding where to put boring jars. This is because they must be run either in compaction or in tenseness in order to be able to trip it in conditions of stuck pipe. The point is where the twine is neither in tenseness nor compaction and hence non advisable to put a jar at that point.
The first option is to look into if the impersonal point is in the drill collars utilizing the undermentioned expression:
WDC: weight of drill collar per foot=144
BF: Buoyancy factor = 0.792
I? : Inclination = 36.86
This is above the drill collars therefore we use this expression below
Therefore the impersonal point is 231ft+94ft = 325ft from underside.
8.2 DRILLPIPE SELECTION
The undermentioned equations are used in design computation for drillpipe choice.
Max. Allowable tensile Capacity
Slip crush factor: 1.42
Design factor: 10 %
Max overpull bound: 100,000 pound
The tensile capacities of the three most used 5 ” 19.5 lb/ft drill pipes is given below:
Premium Class DP
( lb/ft )
Pt ( pound )
Pa ( pound )
Pscf ( pound )
P ( MOP )
Table 8.1: Tensile capacities of Premium category E75. G105 and S135
The effectual or available overpull bound for these pipes are so calculated to do informed determination on which of them is most economical and yet best suited for the occupation. The undermentioned expression are used:
Hook Load= [ ( Length of drill pipe x Adjusted weight ) + ( length of drillpipe in deviated subdivision x Adjusted weight ) + BHA Weight ] x BF
Hence for E75
Hook Load= [ ( 1500 x20.85 ) + ( 9406 Cos ( 36.86 ) x20.85 ) +43400 ] x 0.792
Hook Load = ( 31275+156912+43400 ) x0.792
Hook Load = 104,217 pound
Expected overpull limit= 283,215 -104,217
= 178,998 pounds
Hook Load= [ ( 1500 x21.93 ) + ( 9406 Cos ( 36.86 ) x21.93 ) +43400 ] x 0.792
Hook Load = ( 32,895 +165,040+43400 ) x0.792
Hook Load = 191,137 pound
Expected overpull limit= 396500 -191,137
= 205,363 pounds
Hook Load= [ ( 1500 x22.6 ) + ( 9406 Cos ( 36.86 ) x22.6 ) +43400 ] x 0.792
Hook Load = ( 33,9000 +165,567+43400 ) x0.792
Hook Load = 192,351 pound
Expected overpull limit= 509,776 -192,351
= 317,425 pounds
Since the overpull bound is pegged at 100Klbs and all pipes have excess E75 is chosen since it has an surplus of 78,998 pounds even after accomplishing 100,000lbs. Since the others may even be more due to its quality it is justifiable to settle for E75.
Using the stiffness ratio expression from Well technology and building by H. Rabia:
Stiffness ratio ( SR ) = ( OD2x ( OD12-ID12 ) ) / ( OD1x ( OD22-ID22 ) )
OD2 and ID2 are outer and internal diameter severally of smaller constituent
OD1 and ID1 are outer and internal diameter severally of bigger constituent
OD ( “ )
ID ( “ )
District of columbia
HWDP ( 49.3ppf )
DP ( E75,19.5ppf )
Table 8.5 OD/ID of BHA constituents
SR between DC and HWDP = ( 5x ( 52-32 ) ) / ( 8x ( 82-2.81252 ) ) =2.8
SR between HWDP and DP = 2.8 & lt ; 5.5
This is less than SR of 3.5 for terrible boring such as drawn-out range ( Rabia, 2008 )
Bending subdivision modulus for DCin2
Bending subdivision modulus for HWDPin2
BSR= less than 5.5
Therefore the design is good
9.0 COMPLETIONS PROGRAMME
Well completions serve as an interface between the reservoir and the surface in a safe and efficient manner. It can be divided into two parts, the lower completion and upper completion. The lower completion serves as an interface between the reservoir and the wellbore, while the upper completion provides a safe conveyance conduit from the wellbore to surface.
The SW-P02 well will stop a 300ft wage zone and would be completed as a individual zone completion. The lower completion apparatus would be a Cased Hole Frac political action committee ( CHFP ) . It would be perforated in the interval 9600ft to 9900ft TVD BML. The upper completion would be a individual tube of 4.5 ” production tubing to guarantee that we derive maximal flow rate from the well.
As portion of good control during completions it is necessary to hold barriers to avoid the well fluxing on us. A lower limit of two barriers shall be installed in the completion twine, the Christmas tree and the Surface controlled Subsurface Safety valve ( SCSSSV ) . ( Bellarby, 2009 ) . Packers would besides be set to forestall casing-production tubing annulate flow.
Inflow Performance and sand control:
This deals with the force per unit area bead between the wellbore and the reservoir. In order to guarantee a good flow, we would hold to guarantee that a good boring clay is used in order non to damage the well through clay infiltration. A cased hole Frac political action committee would be used in the lower completions to assist decelerate down the invasion of littorals and guarantee a good draw down. Screens would besides be installed to retain the crushed rock battalions.
Below is a list of completion constituents and their maps:
FUNCTION OF COMPONENT/ EQUIPMENT
This is run to insulate the dead volumes below the perforation and supply a point to latch the screen. It besides serves as a mention point for all completions measurement in footings of deepness.
They serve as sacrificial stop uping systems and hence promotes dependability in sand control
After fracturing the well Proppants are used to shore up these breaks to prolong conductivity between the reservoir to and the wellbore.
Pop Joint and clean pipes
The dad articulation and clean pipes are used in spacing out in completions assemblies.
Lower completions Packer and Production baggers
These baggers form a sealing mechanism between the tube and the shell.
Locator seal assembly
These are threaded seal assemblies supplying isolation between production tube and the ring
A constituent installed in a completions threading where turbulency is anticipated due to alterations in tubing ID
Landing mammillas provide a profile at subdivisions in the completions tubing threading to function as a location for puting and locking subsurface flow controls. ( www.c2c.sg )
Chemical injection spindle
It is equipment in the tube threading apparatus that provides entree for the injection of chemicals into the production tube.
These are installed in the completions assembly for good to supply a topographic point for the installing gages for down-hole monitoring.
Skiding side sleeve/door
This is a device that allows for hydraulic communicating between tubing and the ring. It provides a way for go arounding good kill fluids and serves as a agency for equalizing force per unit area across a deep set stopper after unity trial.
Surface controlled Subsurface safety valve
This is used to close in the flow from the well in the event of loss of unity between surface and wellbore
This serves a conduit for the flow of oil from the wellbore to come up
This is threaded to the tubing caput in the wellspring in order to back up the production tube.
A Christmas tree is a set of valves, choking coils, bobbins and force per unit area gages coupled to the wellspring. Its primary map is to function as a agency of closing in the well, and supply entree during good intercession.
Table 9.1: Summary of completions constituents and their maps
Figure 9.1: Schematic of completions design
It besides proposed that should the over-pressured zone brush hydrocarbons, so a new good be drilled aiming that zone from another slot and completed as a new manufacturer.
In order non to run into hit jobs, the wellbore flight record would be adhered to and appraise done often to guarantee we are non off-track.
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