DRILLING PROGRAMME
Capella L17H
th
October 21 , 2011
Version 2.0
COPY No. 1 (See copy distribution distribution list)
1
Ombú Block
AUTHORIZATION AND APPROVAL APPROVAL
Prepared by:
Date:
Oct - 2011
Date:
Oct - 2011
Date:
Oct - 2011
Date:
Oct - 2011
________________________ _______________________________ _______ Oscar Alfonso Diaz Osorio. Drilling Director
________________________ _______________________________ _______ David Ricardo Pedreros Exploration Geologist Reviewed by:
________________________ _______________________________ _______ Zheng Zhenguo Drilling Deputy Manager Approved by:
________________________ _______________________________ _______ Juan Carlos Ramón Exploration and Business Vice President
__________________________ _________________________________ _______ Yu Dunyuan Du nyuan Drilling Vice President
2
WELL PROGRAMME DISTRIBUTION LIST Copies of this document sent to:
a) Operations
central
files
EEC – Bogotá Bogotá file (original EEC –
sign-off copy)*
b) Drilling Vice President & Manager
Yu Dunyuan
c) Drilling
Zheng Zhenguo
Deputy Manager
d) Exploration and Business Vice President Juan Carlos Ramón e) Drilling Director
Oscar A. Diaz O.
f) Kerui 7502 Drilling Crew
Luis Alfonso Ramirez
3
Contents Contents................................... .................................................... .................................. .................................. .................................. ........................ ....... 4 1
G&G Summary.................. ................................... ................................. .................................. ................................... ..................... .... 7
1.1 Well proposal ............................................. ..................................................... ................................................................... .............. 7 1.2 General information ...................................................... ...................................................................................................... ................................................ 8 1.3 G&G well objectives ..................................................................... ............................... 9 1.4 G&G target/objective description, coordinates and shape ............................... .......... 10 1.6 Formation Tops / Dip / Dip azimuth / lithological description ................................ 13 1.7 G&G TD Criteria ....................................................... ..................................................................................................... .............................................. 14 1.8 TD contingencies ....................................................... ..................................................................................................... .............................................. 17 1.9 G&G Critical Issues related to Objectives and target/reservoir contingency requirements .................................................................. ........................................................ .......................................................... 17 G&G Target and objectives critical issues .................................................... ........................................................................ .................... 17 1.10 G&G Well Well Evaluation E valuation Requirements R equirements (logging/coring/sampling) .......................... . 18 Open Hole LWD .............................................. ..................................................... ................................................................. ............ 18 Anticipated testing requirements ............................................................................ .......... 18 1.11 Offset well information ..................................................... ........................................................................................... ...................................... 19 1.12 Pore Pressure Prognosis .................................................... .......................................................................................... ...................................... 20 1.13 Offset Wells Wells Fluid Contacts ............................................... ...................................... 20 1.14 Well testing Requirements ................................................. ...................................... 20
2. Drilling Equipment Equipment ................................ ................................................ .................................. ................................... ................... .. 17 2.1 Requirements for equipment selection .......................................... ............................. 17 2.2 The Drilling rig and key equipment configuration .................................................... ...................................................... 17
3
Casing Program .............................. ............................................... .................................. .................................. ......................... ........ 18 3.1 Casing program design .................................................................. ............................. 18
4
Well Path Planning.................................. ................................................... .................................. ................................. ................ 20
5
Requirements for Wellbore Quality ........................................................ 22 5.1 Hole quality stand ards in horizontal development well ............................................. 22 5.2 Cementing quality qualit y standards ......................................................... ............................. 23
6
BHA Program ............................................... ................................................................ .................................. ............................ ........... 24
7
Drill Bit Program recommendation ............................................. ........................................................ ........... 24 7.1 Bit type selection recommended.................................. ............................................... 25 7.2 Drilling parameter recommended .................................................. ............................. 25 4
8
Drilling Fluid Program .......................... ............................................ ................................... ................................. ................ 25 8.1 Guidelines for drilling fluid application ..................................................................... 25 8.2 Drilling Fluid Design Principle ............................................ ...................................... 26 8.3 Drilling fluid systems and a nd basic formulations .................................................. .......... 26 8.5 Drilling fluid volumes and reserve of drilling fluid materials .................................... 27 8.5.1 Expected drilling fluid volumes ........................................ ...................................... 27 8.6 Solids control equipment and application requirements............................................. 27 8.7 Requirements for Drilling Fluid Test Instruments ..................................................... ....................................................... 28 8.8 Requirements for Drilling Fluid Management Mana gement on the Surface ................................... 28
9
Cementing Program ............................... ................................................. ................................... ................................. ................ 29 9.1 Guidelines for ensuring cementing quality and oil well life ............................ .......... 29 9.2 Selection of Cementing and Completion Technologies.............................................. 29 9.3 Casing String Design ................................................................................................ .. 30 9.4 Cementing pipe string design ...................................... ............................................... 31 9.5 Selection and placement of centralizers ........................................ ............................. 32 9.6 Cement Slurry Design D esign ........................................................... ..................................... 32
10
Reservoir Protection Protection Program ................................ ................................................. ............................... .............. 34
11
Well Control Control Program................................ ................................................. ................................... ............................ .......... 35 11.1 Selection of o f well control equipment ...................................................................... ... 35 11.2 Requirements for BOP System Inspection and Testing ............................................ 37 11.3 Installation of o f the BOP System .................................................... ................................................................................. ............................. 38
12
Operation Guidelines for Each Hole Section................................. ........................................ ....... 39 12.1 Pre-spud preparation and site construction ..................................................... ............................................................... .......... 39 17 1/2″ hole section ............................................................ section ............................................................ .............................................. 40 12.3 12 1/4″ 1/4″hole section .............................................................. ....... ............................................................................................ ..................................... 41 12.4 8 1/2" hole drilling ...................................................... .................................................................................................... .............................................. 43 12.5 Precautions P recautions for drilling d rilling hazards ................................................... ............................. 43
13
Wellhead equipment equipment for completion ............................................. ..................................................... ........ 47 13.1 Casing head specification ............................................................ ............................. 47 13.2 Wellhead protection ........................................................................................ .......... 47 13.3 Completion requirements ............................................................ ............................. 47
14
HSE requirements requirements ................................. .................................................. .................................. ................................. ................ 49 14.1 Basic requirements ..................................................... .............................................. 49 14.2 Liquid and solids waste w aste managment program p rogram ................................................ .......... 50 14.3 Waste management objects (HSE)............................................... ............................. 50 5
15. Logistic issues............................................................................................. 51 16
Requirements for drilling information report...................................... 51
17
Drilling cycle forecast.............................................................................. 52
6
1
G&G Summary
1.1 Well proposal Energy PLC Suc. Colombia is proposing to drill Capella-L17H Horizontal Development Well from the Capella-L location, under Ombú E&P Contract in Capella Field as a horizontal well towards the mid area of Capella field.
Capella-L17H will be drilled as horizontal well and is located in Los Pozos
Village (Colombia) (Figures 1 to 3). Capella Structure is a faulted anticline NE oriented about 28 Km NE-SW by 4.5 Km NW-SE (Figure 4 to 7).
Capella-L17H will be conducted as a Horizontal well to reach and navigate through the Mirador Sand reservoir (producing in Capella Wells), in a central position in the Capella structure (Figure 4 to 7). Capella-L17H would TD about 5190, 20ft MD, therefore it is not expected to reach Mirador OWC (-2159ft TVDss), based on the same contour interval that was encountered by the Capella-L11 Well, (Figure 8).
Capella-L17H is designed to produce from Mirador Upper Sand. This well will be conducted in horizontal profile to navigate about 274, 4 meters up dip in SE direction through Mirador Sand Horizon 2 to confirm the oil production increasing shown in horizontal wells from location F.
Figure 1. Capella-L17H location trajectory from Capella-L toward Capella-F 7
location
The principal risks associated with the well are:
Minor changes of the Mirador Sandstones. Navigate the most along Mirador Sand # 2. Sidetrack if real trajectory is too different from plan. Prognosis top depth from seismic information could change after drilling depth real section. Water coning as we found the OWC in Capella – L11.
Figure 2. TVDss Map Top Mirador with Capella-L17H trajectory with SE direction that will navigate up dip in the western flank of anticline
1.2 General information Table 1-1 Well general identification
Data
Description Required well operations Purpose/Target:
Horizontal Well
Proposed Well Name:
Capella-L17H
Target Horizons:
Mirador Sand Horizon 2
Lahee Well Classification:
Development
Well Type:
Development
Drilling Classification: Completion Size: Well Location:
County La Macarena (Meta)
8
Comments
Well Surface Origin):
Coordinates
GAUSS
(Bogotá N = 724.792,72 m E = 943.584,93 m
Target Coordinates:
Well Bottom Origin):
Coordinates
N = 724.432,31 m E = 943.929,19 m GAUSS
(Bogotá N = 724.233,93 m E = 944.118,68 m
Primary Target:
Mirador Sand Horizon 2
Objective Depth:
-2105 ft (Subsea – TVDss) 4290,1 ft MD 3338,0 ft TVD
Navigation Distance
274,35 m, 900ft
Ground level elevation:
Location GLE 1212.92 ft
Rotary Table Elevation:
1232,92 ft amsl (Aprox. 20 above GL)
Expected well total depth:
5190,2 ft MD 3338,0ft TVD ( -2105 ft TVss)
Proposed Spud Date:
November 4 , 2011
th
1.3 G&G well objectives
Increase production rates through increasing drainage length of Mirador Sand A, 274m (900ft) up dip in Mirador Sand Horizon 2
by drilling
from Capella-L location (Figure 5, 8 and 9).
Drill Capella-L17H Horizontal well in Southeast direction with 136° average Azimuth (Figure 3).
Drill Capella-L17H horizontal well parallel to Capella-F10H, Capella-12H ST and Capella-F13H (Figure 4).
Navigate the most within horizon 2 of Mirador Sand A, while drilling horizontal well (Figure 8). Stay higher than OWC @ -2159ft TVDss, found in Capella-L11 that reached only Horizon 1 with oil (Figure 8 and 9).
Test the oil production capability of the Mirador sandstones and verify the continuity of producer sands and petrophysical properties.
Control Mirador Sand Horizon position by acquiring Resistivity and GR logs with LWD tool.
Control the lower part of Arrayan that creates wash-outs. Take into account lessons learn in Capella F7, Capella-F10H, Capella-F12H ST and Capella-F13H.
Deliver well in full compliance with the well Integrity requirements.
9
1.4 G&G target/objective description, coordinates and shape Capella-L17H will be drilled from the following cellar center coordinates in Capella L location: Center cellar Coordinates GAUSS (Bogotá N = Origin) E=
724.792,72 m 943.584,93 m
Capella-L17 Horizontal Capella-L17 Horizontal will be drilled to reach the next target coordinates until the bottom as follows (Figure 3 and 4): Capella-L17 Horizontal Entry Point -Target Coordinates GAUSS (Bogotá Origin): N = 724.432,31 m E = 943.929,19 m Capella-L17 Horizontal Well Bottom Coordinates GAUSS (Bogotá Origin): N = 724.233,93 m E = 944.118,68 m
10
Figure 3
Vertical Profile and Plane View of Capella-L17H Plan
11
Figure 4 Plane View of Capella-F10H, Capella-F13H, Capella-F12HST, Capella-F16H drilled and Proposed Capella-L17H Plan over TVDss Mirador Structural Map
.
1.5 Reservoir description Mirador reservoir data Gross Thickness 45 feet TVD (Mirador Horizon 2) Mirador Sand Oil Water Contact -2159 feet TVDSs Target Coordinates at top of N =724.432,31 m reservoir GAUSS (Bogotá Origin) E =943.929,19 m Target shape and area Faulted anticline (22,000 acres) Last reservoir pressure 1312.69 psi at 3362 feet (TVD)
12
1.6 Formation Tops / Dip / Dip azimuth / lithological description Prognosis Horizontal Hole TVD (feet)
Top TVDss (feet)
MD (feet)
Quaternary
0
1212,93
0
Fm. Arrayán
155,00
1077,93
155,00
Fm. Mirador
3298,00
-2065,10
3888,90
Fm. Mirador – Horizon 2 Max TD
3338,00 3333,00
-2105,10 -2100,10
4290,10 5190,20
FORMATION
* TVD BRT = TVDSS + GLE + RTE Note:
(Assume RTE = 20 ft)
The drilling program indicates the Capella-L17H well TD depth @ +/- 5190 ft MD.
However
in case of Sand A thickness variation, the plan is to resume drilling up to EEC central offices geologist indications.
Arrayán Formation This formation was made up primarily of multicolor soft claystones and siltstones with minor sand. These sediments frequent plant imprints and carbonaceous material. In the middle section the change was evident from claystone into silty shales, medium light green gray, medium light gray and pale brown, brittle some fossil with small (0.5 cm) gasteropods. Some shale dark gray, carbonaceous very piritic was also reported. In the lower section of the formation, the shale became predominantly medium dark gray brown, silty, brittle. This shale severely caved, in affecting the normal drilling operation and obstructed the logging of the well. The Arrayán formation uncomformably overlies the Mirador formation.
Mirador formation Mirador Formation is the target in Capella-L17 H well. Mirador average gross thickness is about 120ft and in this area of Capella F location has been divided into Upper Mirador Sand that has three horizons separated by mudstones thin intervals, and the lower Mirador that is mainly mudstone. drilling results of Capella-F7 and Capella – F10H,
Based on
the expected lithology is: Unconsolidated sandstones
composed mainly by quartz, predominantly medium grain size, with minor presence of coarse to very coarse grains, rounded to subrounded, locally subangular, poor sorting. According to borehole image data, sequence average dips are 6° /90º (azimuth). It occurs intercalated with shale and mudstone.
Cretaceous Fractured conglomerates Polimictic conglomerate made up of quartz and a notable presence of metamorphic rocks. 13
Very hard,
blocky, predominant pebbles and cobbles grain size. Mineral accessories as pyrite, galuconite and mica are present. Siltstone gray and dark gray, consolidated, blocky to sub blocky, locally laminar.
1.7 G&G TD Criteria Capella field play is defined as an NE trending anticline fault-bounded (Figure 2).
Capella-L17H will
be drilled in the central-south part of the structure, where Mirador Sand shows good reservoir properties in thickness, porosity and permeability. Capella-L17H optimal path planning was based on the current knowledge of integrated geological information from Ombu 3D Seismic, and Capella-L11, Capella-F7, Capella-10H & Pilot, and Capella-F12ST. Seismic response in Ombu 3D inline 236 over Capella-L17H is the same over Capella-F10 H at Mirador level, so is expected similar conditions in this well. Capella-L17 H was planned to navigate up dip in the west flank of anticline from Capella L location toward Capella F location (Figure 5), through the same horizon that Capella-F10H (Figure 5).
Figure 5
Time Seismic Inline 236 over Capella-L17H, and Capella-F10H, showing the horizontal well trajectory that was
navigated in the crest of anticline through Mirador Horizon 2 with Capella-F10H and the planned trajectory to navigate with Capella-L17H in the western flank of anticline.
After drilling Capella-F7, Capella-L11 and Capella-F10 Pilot, were defined three horizon of
14
Mirador
Upper Sand (Figure 6, 7 and 8), where petrophysical analysis shows the higher potential in Horizon 2 and 3 of Mirador Upper Sand; Capella-F10H production increasing have confirmed this evaluation. Oil water contact was found in Capella-L11 at -2159ft TVDss, for this reason Capella-L17H is planned to navigate higher than OWC at -2159ft TVDss (Figures 6, 8 and 9). Mirador average thickness in these well is about 120ft, with Horizon 1 average thickness about 25ft, Horizon 2 average thickness about 45ft and horizon 3 average thickness about 30ft; Mirador base with average thickness about 20ft (Figure 6).
Figure 6 TVDss Well Cross correlation across Capella-L11, Capella-F7, and Capella-F10 Pilot, showing Upper Mirador with three defined horizons and the Oil water contact at -2159ft TVDss. Capella-L17H will navigate 500 m far away from Capella-L11 to Capella-F7 through horizon 2.
Capella F10 Pilot dipmeter analysis indicates Mirador Formation characterized by piled cylindrical electro-sequences, with bimodal paleo-stream indicating a flow regime NE SE (Figure 7).
15
Figure 7 Piled channel sequence (Horizons 2 & 3 of Upper Sand Mirador) in Capella-F10 Pilot. Capella-L17H will stay in horizon 2 while drilling horizontal section
Figure 8 Depth cross section across arbitrary line over Capella-L11, Capella-L17H and Capella-F7, showing Cap-L17H horizontal well trajectory that will navigate up-flank toward the Southeast in Mirador Horizon 2. Capella-L17H trajectory will be higher than Oil water contact found in Capella-L11 at -2159ft TVDss (Vertical scale is different to horizontal scale).
16
Figure 9 TVDss Well Cross correlation showing Capella-L11, Capella-L17 H prognosis, Capella-F7, Capella-F10H & Pilot and Capella F12ST. Capella-L17H is planned to stay in horizon 2 as Capella-F10H. In Capella-L11 this horizon was found below Oil Water Contac (Green line in the section) and is the best producer horizon in existing horizontal wells.
1.8 TD contingencies Planned TD in Capella L17 H is 5190,2ft MD (3333ft TVD, -2100ft TVDss), however TD contingencies must be taken into account if while drilling the sequence is muddier than expected.
1.9 G&G Critical Issues related to Objectives and target/reservoir contingency requirements G&G Target and objectives critical issues G&G target is Mirador Sand A at -2105’ TVDss in entry point (N: 724432.30 E: 943929.20) with 274m navigation in Mirador Sand A interval staying mostly in Horizon 2. Pilot well will not be drilled to confirm Capella-L17H Mirador Top and Sand A thickness variation in advance. Variation of petrophysical properties in Mirador Sand A could be present take at count the variation in Sand A quality reservoir properties through Capella wells.
17
1.10
G&G Well Evaluation Requirements (logging/coring/sampling)
Open Hole LWD Horizontal well:
SYSTEM
LWD
LOG MFR (Multi Frequency Resistivity), GR
LOG INTERVAL TOP
LOG INTERVAL BOTTOM
200ft MD before Mirador Prognosis Top
TD
Commentaries
REMARKS: Geological model will be updated with real data while drilling Capella L17H, therefore prognosis depth could change. Real depth will be notice for logging plan updating.
Geological Sampling Two sets of wet samples each 30ft below the 13 3/8’’ casing (350t) up to TD. Two sets of dry samples each 30ft below the 13 3/8 ’’ casing (350ft) up to 50ft above proposed Mirador Formation Top, from this point samples each 10ft up to TD.
Note: Even though, no samples will be storage for the interval (Surface to 350ft) a description of these interval must be done every 30ft.
Anticipated testing requirements The testing program will depend on the analysis of data obtained while drilling the well.
18
1.11
Offset well information
Capella-L17H offset wells are Capella-L11 and Capella-F7 vertical wells and Capella-F10H, Capella-F12HST, Capella-F13H and Capella-F16H horizontal wells (Figure 10). Capella-F10H, F13H, F12H and F16H existing horizontal wells path have been oriented toward South and have been drilled from location F.
Capella-L17H path will be oriented in the same direction of F10H,
F12HST, F13H from location L (Figure 10).
Figure 10 Vertical offset wells Capella-F7 and Capella-L11 and horizontal offset wells Capella-F10H, Capella-F12H, Capella-F13H and Capella-F16H.
19
1.12
Pore Pressure Prognosis
Reservoir Mirador Sand A
1.13
Reservoir pressure (Psia) @ 1314
Pore pressure data Offset wells used (ft, TVDss ) measurements from
psi
-2118
Capella-A1
Data obtained from
Comments
PBU
At 3362 ft TVD
Offset Wells Fluid Contacts
Mirador Oil Water Contact in Capella Field was found at -2159ft TVDss based on Capella-L11 petrophysical evaluation. Possible Fractured Conglomerate oil water contact from Capella logs answers, oil-gas shows and production test is defined at -2256ft TVDss. This is based on production test results from Capella-F7 well that recorded data in the aquifer, together with gas-oil shows and log interpretation. However, uncertainty around the Fractured Conglomerate OWC exists with petrophysical evaluation, oil and gas shows in Capella wells under -2256ft TVDss (Figures 5, 7 and 8).
1.14
Well testing Requirements Well Produ ction tests requi rements
Test
Requirement
Fluid samples at surface Take continuously during test, samples for oil conditions and water at well head.
Initial Test / /Conglomerate
PCP lifting will be installed and will be Mirador developed the production test, 5 days flowing period at stable condition. Followed at least 4 days closed. Same test for each zone.
20
Comments / Purpose Monitoring properties changes during early production time (density, viscosity, salinity, water and oil samples for full characterization, etc). Identify formation damage, build IPR curve and plan stimulation jobs from skin damage identified. Use pressure and temperature downhole sensors, packer in annulus and check valve in tubing for good closure. (Packer will be used or not after results ontained from capella-Z19).
2. Drilling Equipment 2.1 Requirements for equipment selection The drilling depth in Ombu Block is generally about 3000ft ~ 4000ft (TVD), and the maximum load in drilling operations is about 135klb （net weight in air). Based on the rig load selection principle and well control equipment requirements, it is determined that the load capacity and configuration of the rig equipment to be selected should satisfy the requirements for 750hp. Taking the great load into consideration, before the rig is moved to location, all equipments, especially the derricks, substructure, hoisting system, rotary system, etc. should be tested and qualified, to ensure safety of the system when hoisting the maximum casing load with all stands remaining on the drill floor. All equipments should be in good condition. Equipment protection and safety devices should be completely provided. The power and driving system should be efficient. The mud circulating, cleaning and treatment system should be able to meet the requirements for flow rate, mud property maintenance and mud storage in different hole sections.
2.2 The Drilling rig and key equipment configuration Table 2-1 The Drilling rig and key equipment configuration No.
Name
Power & load
Number
1
Derrick
375klb
1
2
Crown block
375klb
1
3
Traveling block
375klb
1
4
Hook
375klb
1
5
Swivel
375klb
1
6
Rotary table
375klb
1
7
Drawworks
750hp
1
8
Top drive
250 ton
1
9
Electromagnetic brake
10
Mud pump
1000hp
2
11
Diesel engine
810kW
3
12
Generator
320kW
2
13
Double-ram BOP
3000psi
1
14
Killing manifold
3000psi
1
1
17
Remark
No.
Name
Power & load
Number
15
Choke manifold
3000psi
1
16
Driller's console
1
17
Choke control console
1
18
Remote control console
1
19
Surface high pressure manifold and hoses
1
20
Desander
45kW
1
21
Desilter
45kW
1
22
Shale shaker
23
Degaser
11kW
1
24
Centrifuge
69kW
1
25
Hydraulic tongs
1
26
Mud mixer
7
27
Mud filling device
1
28
Circulating tank
1400ft
3
4
29
Mud reserve tank
1400ft 3
1
3
2
Remark
Derrick2000
Casing Program
3.1 Casing program design Table 3-1 Casing program design Casing / liner description
Hole size (in)
Casing size (in)
MD (ft)
TVD (ft)
Cementing section (ft)
Surface casing
17 1/2
13 3/8
345
345
0～345
Intermediate casing
12 1/4
9 5/8
3891
3298
0～3891
Slotted Liner
8 1/2
7
5175
3333
Note: In the drilling process, intermediate casing setting depths will be adjusted according to the top of real drilled formations.
18
Table 3.2 Explanations on casing program design Hole size (in)
Section TD (ft MD BRT)
26”
0’ – 35’
17 ½”
35’ – 350’
12 ¼”
350’ – 3894’
8 ½”
3894’ – 5190’
Total Depth Criteria Sufficient depth to obtain competent shoe for conductor. (Civil Works) Pass through the Quaternary conglomeratic sandstone formation to case off and confirm enter in the Arrayan sandstone with intercalation of sand. Pass through Arrayan sandstone with intercalation of sand. Case off the Mirador Top Formation. Mirador Formation and unconformity to well TD. Slotted liner completion
Fig. 3-1 Casing program design schematic
19
4
Well Path Planning Table 4-1 Well path planning parameters
20
21
Fig. 4-1 Vertical Profile and Plane View of Capella-L17H Plan
5
Requirements for Wellbore Quality
5.1 Hole quality standards in horizontal development well
The survey interval should be less than 300ft in vertical section. MWD should be used to do real time survey from build section to TVD.
Dogleg rate in vertical section should be less than 2°/100ft. Dogleg rate of long radius should less than 4°/100ft in build section and turn section. Dogleg rate of intermediate radius and short radius should be controlled based on trajectory design.
Wellhead Housing Inclination should be less than 0.5°.
22
Table 5-1 Target rectangle Horizontal section(ft)
width(ft)
length(ft)
0-1500
6
30
≥1500-3000
6
45
≥3000
6
60
Notes: If the thickness of payzone is more than 20ft, the width should be less than 9ft. If the thickness of payzone is more than 15ft, the width should be less than 6ft. If the thickness of payzone is less than 15ft, the width should be less than 3ft.
5.2 Cementing quality standards 5.2.1 Quality of cement bond
CBL: the relative magnitude of acoustic amplitude is less than 15%, good; less than 30%, normal; more than 30%, bad.
VDL: the pipe arrivals are no or weak and formation arrivals are clear, good; weaker and clearer, normal; strong and weak, bad.
5.2.2 Level of cement
The cement should be returned to surface in viscous oil thermal production well. 5.2.3 Effective zones isolation
If isolation length of individual zones is more than 30ft, the effective isolation length should no less than 15ft. If isolation length of individual zones is less than 30ft, the effective isolation length should no less than 50% isolation length. If isolation length of individual zones is less than 5ft, these zones are treated as one zone.
5.3 Casing pressure test Table 5-2 Casing pressure test Casing size
Production well
Injection well
Gas well
Pressure drop allowance
5″～7″
2000psi
2000～3000psi
＞3000psi
70psi/30min
9-5/8″～10-3/4″
1500psi
1700psi
＞2000psi
70psi/30min
23
6
BHA Program
BHA configuration for this block should be determined based on BHA optimization concept. In actual drilling operations, BHA can be adjusted in time according to characteristics of formations being encountered. The selected BHA should be compatible with the formation to improve ROP and realize the objective of drilling operations which is based on contractor’s experiences.
6.1 Proposed BHA for each hole section Table 6-1 Proposed BHA for each hole section No
Section (ft)
1
0～350
17 1/2″ Bit+8″ DC×2+17 1/4″ stabilizer×1+8″ DC×4+5 ″ DP
2
～3891
12 1/4″ Bit+8 1/2″ 1.5°PDM ×1+8 1/2″ MDC×1+8 1/2″ LWD+8″ NMDC×1 +5″ HWDP×6+6 1/2″ drilling jar×1+5″ HWDP×21+5 ″ DP
3
～5190
8 1/2″ Bit+6 3/4″ 1.5°PDM ×1+6 3/4″ MDC×1+6 3/4″ LWD+6 3/4″ NMDC×1+5″ HWDP×6+6 1/2″ drilling jar ×1+5″ HWDP×21+5 ″ DP
BHA
6.2 Drill string strength check data Table 6-2 Strength check data of drilling tools Location of neutral point: 5″ OD DP
Depth of neutral point (ft):3275
Strength Check Data Name Yield Spud of OD thickness Steel Weight Length Tensile Torsional MISES strength No. drilling (in) (in) grade (lb/ft) (ft) coefficient coefficient coefficient ( lb/in2) tools
7
1
HWDP
5
1
2
DP
5
0.362
G-105
48.63
885.82
19.5
3939.7 105000
28.26
35.54
14.52
15.83
5.11
Drill Bit Program recommendation Based on bit type selection methods, formation rock characteristics in Capella Block and drilling data from offset wells in this area, bit types are selected properly and hydraulic parameters are designed exactly to achieve the objective of improving ROP, increasing bit footage and reducing drilling cost.
In the drilling process, bit type can be adjusted in time according to actual bit application on site and the experiences of contractor.
24
7.1 Bit type selection recommended
Table 7-1 Bit type selection program No
Formation
Size (in)
Bit
Quantity
section (ft)
footage (ft)
1
Q、A
17 1/2
HAT127
1
～350
350
2
A、M
12 1/4
PDC（M316）
1
～3894
3544
3
M
8 1/2
PDC（M316）
1
～5190
1296
Note: In the drilling process, bit type can be adjusted according to actual conditions on site. 7.2 Drilling parameter recommended
Table 7-2 Drilling parameter recommended B it
F o ti
o o rd n e r
rm a -
Drilling parameters Hydraulic parameters Hole Nozzle Flow SP Bit Circ. Jet Bit Spec. Annu. Power section WOB RPM mpac (mm) rate pre. PD PD vel. HP HP vel. usage (ft) (kN) (r/min) (kN) (L/s) (MPa) (MP MPa (m/s) (kW) /mm (m/s) (％)
1 Q、A 0～350 2 A、M ～3894
12,12, 60～ 120～ 180 12,12 100
48 17.72 2.22 5.5 1.08 73.47 4.22 2.42 1.38 36.85
～5190
10,10, 60～ 100～ 120 10,10 80
30
3
M
21
3
7
1.3
81
39
2.1
1.1
32
Note: ① Data in the table are theoretically calculated values that can be adjusted properly on site according to actual operating conditions. ② SP pre.=Stand pipe pressure; Bit PD=Bit pressure drop; Circ. PD=Circulating pressure drop; Jet vel.=Jet velocity; Bit HP=Bit hydraulic power; Spec. HP=Specific hydraulic power; Annu. vel.=Annular velocity.
8
Drilling Fluid Program
8.1 Guidelines for drilling fluid application
Drilling fluid type: High quality water based drilling fluid will be used.
Drilling fluid properties: Based on formation pore pressure and collapse pressure and according to actual drilling conditions, adjust drilling fluid properties properly and perform near-balanced drilling.
The Mirador formations are prone to sloughing and tight hole. The drilling fluid should have good inhibiting property and sloughing resistance and can maintain reasonable rheological property to clean the wellbore. While drilling in reservoir, pay more attention to reservoir
25
protection.
While drilling in the reservoir, observe changes of drilling fluid properties carefully and adjust drilling fluid properties in time. It should be noted that don't weight drilling fluid blindly to avoid fracturing and contaminating the reservoir.
In drilling horizontal section, the drilling fluid should have good lubrication, good rheology for cuttings carrying out.
8.2 Drilling Fluid Design Principle
Drilling fluid application should be beneficial to discovering and protecting the reservoir, to collecting geologic data, to fast and safe drilling, to removing oil & gas, to preventing and treating complex downhole troubles and to environmental protection.
Formations to be encountered in this well are prone to sloughing, lost circulation and pipe sticking. Therefore, drilling fluid should be able to resist sloughing, lost circulation and have the capacity of protecting the reservoir.
Drilling fluid design for this well is conducted according to ctual drilling data from offset wells. The main purpose is to discover and protect the reservoir by performing near-balanced drilling.
8.3 Drilling fluid systems and basic formulations
According to characteristics of formations to be encountered in Capella Field, drilling fluid should maintain low solids and lower filter loss and have good inhibiting and rheological properties to ensure safe and fast drilling. The key is to protect the reservoir.
8.3.1 Drilling fluid systems
Table 8-1 Drilling Fluid Types for Each Hole Section No 1
Hole Size（in） Section（ft） 17-1/2 0～350
Mud type Bentonite+Fresh water
2
12 1/4
350～3894
Inhibitive polymer anti-collapse+Lubricator
3
8 1/2
3894 ~ 5190
Low density - No solid polymer + shielding protection material.
26
8.4 Design of drilling fluid properties
Table 8-3 Drilling fluid property for each hole section Drilling fluid properties
Properties
0～350（ft）
350～3894（ft）
3894 ～5190（ft）
Mud weight
（ ppg）
8.8 – 9.0
9.2 – 10,3
8.6 – 8.8
Funnel viscosity
（sc/qt）
40 - 50
50 – 60
50 - 70
API Fluid Loss
（cc）
N/C
3- 6
3- 5
4/6/9 – 7/15/20
4/6/9 – 7/10/15
9.0 – 9.5
9.0 – 9.5
15 – 20
15 - 20 11 - 16
Gels ft2） pH
（lb/100
Yield point ft2）
（lb/100
Plastic viscosity
（cp）
15 – 18
Solids
（%）
<10
Kf
<0.1
<0.05
8.5 Drilling fluid volumes and reserve of drilling fluid materials 8.5.1 Expected drilling fluid volumes
Table 8-4 Expected drilling fluid volume for each hole section Surface circulation Well bore Additional Spud No. volume（ bbl） volume（ bbl） （ bbl） 1 503 145 289 2 503 403 681 3 503 600 600
Total（ bbl） 937 1587 1700
8.6 Solids control equipment and application requirements Solids control equipment should be provided as required. The shale shaker, desander, desilter and centrifuge will be used for the four-stage sand removal to control sand and solids contents within a reasonable range and create conditions for improving ROP. Screen mesh of the shale shaker should be replaced in time according to formation changes. Screen mesh should be increased with the increase of formation hardness. Application of the desilter will be decided according to actual drilling requirement. For solids control equipment and application requirements, see the table below.
27
Hole section
Table 8-5 Solids control equipment and application requirements Solids index Shale shaker Desander Centrifuge Solids Running Treating Running Treating Running ρ Cs content Mesh time volume time volume time (ppg) (%) (%) (%) (gal/min) (%) (gal/min) (%)
17 ½”
8.8 - 9.0
12 ¼”
9.2 – 10,3
≤0.3
8 ½”
8.6 - 8.8
≤0.1
6～8
>60
100
≥880
100
≥264
100
>60
100
≥680
100
≥264
100
8.7 Requirements for Drilling Fluid Test Instruments
Drilling fluid test instruments should be provided as listed in the table below to ensure that drilling fluid properties can be tested and maintained in time on the rig site. All instruments should be calibrated before sending to the rig site and they should also be often calibrated when they are in use to enshure the accuracy of the measured data. Table 8-6 The least offering of drilling fluid test instruments Name Quantity Name Drilling fluid densimeter 2 MBT measuring equipment Marsh funnel viscosimeter 2 Stopwatch 6-speed rotary viscosimeter 2 Alarm clock API medium pressure filter press 1 Electric mixer Solids content tester 1 Electric stove 2 Timer pH-meter （or pH indicator strip） Mud cake friction meter 1 1000ml mud cup Sand content tester 2 Filtrate analyzer & tester
Quantity 1 2 1 2 2 1 10 1 set
8.8 Requirements for Drilling Fluid Management on the Surface
Requirements for killing fluid reserve system are: The reserve volume should meet the given demands and the killing fluid can be pumped directly to the circulating system.
Storage tanks should be provided as required for reserving killing fluid. Two long- shaft mixers operating normally should be installed on each storage tank. Storage tanks should be connected with the lines for the short way circulation and the killing fluid should be able to be pumped to the circulating system directly.
It required that each circulating tank of the surface circulation system should be provided with two mixers and the drilling fluid gun will work normally.
Rain & water protection facilities should be provided for the circulating, reserving and weighting 28
systems.
It is required that an additive make-up tank with the volume of no less than 350ft 3 should be provided, and the mixers should meet the demands of making up the additives.
To meet the demands of curing the losses, it is required that a LCM tank with two mixers should be provided whose volume is 530～700ft3.
Drilling fluid materials should be stored in a special room. If they have to be placed in the open air, pads and covers should be used to protect them from rain and moisture. Drilling fluid should be treated on the basis of test results to prevent downhole troubles or accidents resulting from improper treatment.
The bottom of the waste liquid pit and the cuttings pit should be lined with impermeable materials to avoid seepage of polluted water and prevent cuttings from piling up directly on the ground.
9
Cementing Program
9.1 Guidelines for ensuring cementing quality and oil well life
Try to control hole enlargement ratio within 10% and prevent very irregular borehole.
Casing centralizers should be placed properly. While running casings in hole, note to move casings and ensure they are in the center of the wellbore.
On the premise of ensuring borehole safety, try to increase cement injection rate and improve displacement efficiency.
Reasonable cement slurry system: Select low filtration, sand-cement slurry. Control free water in the cement slurry to zero and water loss to less than 100ml to improve thermal stability of the cement slurry.
Ensure continuity of the cementing operation.
9.2 Selection of Cementing and Completion Technologies 9.2.1 Requirements of cementing and completion
Height of the cement plug within the casing should conform to the design requirement.
All the drilling fluid within the annular space of the cemented interval should be displaced by cement slurry. No drilling fluid is allowed to be left.
Cement sheath between the casing and the borehole wall rock should have sufficient cementing strength that can withstand the impact of the pipe string being run in hole.
After the cement is set, no oil, gas and water should flow out from outside the casing and there 29
should be no channeling among various pressure systems in the annulus.
The set cement should withstand invasion of oil, gas and water for a long period of time and the effect of high temperature.
9.2.2 Selection of cementing and completion technologies
Completion method will be selected based mainly on characteristics of reservoir rock, reservoir features and requirements of oil production technology in order to reduce reservoir damage, improve production capacity and prolong oil well life. Cementing selection as follow.
Surface casing using conventional cementing.
Production casing using screen top cementing, cement plug return to surface. Table 9-1 Basic Parameters for Cementing and Completion
345
Cement returning depth (m) Surface
Conventional
3891
Surface
Conventional
Spud No.
Hole size (in)
Casing size (in)
Casing setting depth (ft)
1
17 1/2
13 3/8
2
12 1/4
9 5/8
3
8 1/2
Cementing & completion mode
Remark
Slotted liner from 3741’ MD to 5175’ MD
7
9.3 Casing String Design 9.3.1 Casing string design principle
Casing design is to ensure that the maximum stress on the casing in all the life time of the well is within the allowable safety range so as to protect the oil & gas well. The design principle is as follows:
Requirements for drilling, production and payzone modification technologies can be satisfied.
In casing design, the influences of collapse, burst and stress changes in the process of exploitation should be taken into consideration. The balance between casing strength and casing string mechanics should be established. To ensure that safety is put on the first place, casing design consideration is based on the assumption that the casing is in the most dangerous downhole condition.
Safety factors for casing string strength design are as follows. Collapse resistance: 1.125, burst resistance: 1.125, tensile: 1.8.
On the premise of meeting strength requirement, the cost should be as low as possible. 30
9.3.2 Casing string design and strength check
According to drilling & development program for this Block, in casing selection, besides meeting strength requirements, the influence of the casing on oil well life should also be taken into consideration. Casing string design is shown below. Table 9-2 Casing string design and strength check Safety factor Tensile Collapse Burst St Sc Si
Casing / liner description
Casing size (in)
MD (ft)
Steel grade
Wall thickness mm
Thread
Unit weight (lb/ft)
Surface casing
13 3/8
345
K55
10.92
BTC
61
31.45
7.92
11.78
Production Casing
9 5/8
3891
N80
8.94
BTC
43.5
6.71
9.05
5.74
Slotted liner
7
5175
N80
10.36
BTC
29
Note: a. Casing strength designs are calculated based on formation pressure data provided by the geologic design. Cementing design should be proved again on site according to actual conditions. b. All casing collapse strengths are calculated based on 100% empty casing. c. Threads of all casings are required to be coated with high temperature thread sealant. d. Related cementing tools and accessories must match the threads of casings. Their strength should not be less than that of the casings in the specific hole section. Enough short casings with variable, threads should be got ready.
Table 9-3 Casing data Unit weight Thread kg/m type (lb/ft)
Tensile strength klbs
Collapse strength psi
Burst strength psi
61
962
1.540
3.090
BTC
43.5
1005
3810
6330
BTC
29
676
7,020
8,160
OD In
Steel grade
Wall thickness mm
13 3/8
K55
10.92
BTC
9 5/8
N80
8.94
7
N80
10.36
9.4 Cementing pipe string design
Table 9-4 Cementing pipe string design Spud No.
Casing size （in）
1 2
13 3/8 9 5/8
3
7
Cementing pipe string float shoe +casing string +landing joint float shoe +1 casing+float collar + casing string +landing joint Shoe + pup joint of sloted liner + Ring seal sub + Sloted liner + thermal extention loint + Liner hanger
31
Fig. 9-1 Detail 7” Casing Capella L17H – Three Phases
9.5 Selection and placement of centralizers
Spring centralizers will be used. In the reservoir section, one centralizer is placed every 2 casings, and in other hole sections, one centralizer is placed every 4 casings.
Centralizers will be placed per API Standards to ensure that casings will be run in hole smoothly and be centralized.
9.6 Cement Slurry Design 9.6.1 Cement slurry design principle
Properties of the cement slurry must be stable under downhole temperature and pressure.
The cementing slurry should be set and reach the specific strength within the fixed WOC time.
The set cement should have very low permeability.
32
9.6.2 Selection of cement slurry
The cement slurry system with low water loss will be selected to improve thermal stability of the cement sheath, adding quartz sand to cementing slurry by 30~40%.
Additives such as water loss reducer, defoamer, dispersant, etc. should be added. Additives to be used should satisfy the requirements of cement slurry properties, ensuring operation safety and cementing quality and benefiting reservoir protection.
9.6.3 Requirements of cement slurry properties for the reservoir
Cement for oil wells must be tested carefully before use to check its properties. Properties of cement slurry with additives should be tested, including tests on density, thickening time, free water and rheology, tests on tensile strength of the cement bond as well as tests on compatibility of the cement slurry with the preflush and drilling fluid.
Table 9-5 Cement slurry property parameters for the reservoir Properties Density (g/cm3)
Property requirement
Remark
1.90
Rheology（cm）
＞25cm
Water loss（ml）
＜100ml/1000psi，30min
Free water content （ml）
0
Thickening time（h）
Total cementing time +1h
Tensile strength
24hr ＞2000psi
9.6.4 Cement volume calculation
Table 9-6 Cement volume calculation Enlarge Excess Cementing rate of Size Cementing Slurry Density Quantity cement No caliper (in) type Type (ppg) (klb) section（ft） （％） （％） Inner string Class 1 17 1/2 15.4 15 50 98 0～350 stabbing G Cementing Lead 2 12 1/4 above the top Class 13.6 10 80 118 0～2791 of Screen G Cementing Tail 12 1/4 2791～3891 above the top Class 15.4 10 80 47 of Screen G Note: Cement volume and cement returning depth are theoretical data which should be revised in operations according to measured data. 33
10
Reservoir Protection Program The drilling fluid system that is compatible with the reservoir will be used and drilling fluid
properties should be controlled to reduce formation contamination as much as possible. Measures to be taken are as follows: a.
Polymer drilling fluid system will be used to reduce and prevent harmful substances from invading the reservoir.
b. Control the low density solid content in the drilling fluid and avoid solids from migrating and damaging the reservoir. c.
For drilling fluid used in the payzone section, API filter loss is controlled to ≤5cc. Prevent water sensitivity effect from damaging the reservoir.
Adopt the shielding & temporary plugging technique and use kerite additives to prevent harmful substances from invading the reservoir.
Perform near-balanced or underbalance drilling technology. Predict formation pressure in time and adjust drilling fluid density correspondingly. According to related technical regulations, the additional density is controlled to 0.42-0.83 ppg in the reservoir and to 0.58-1.25ppg in the gas zone. While tripping out of hole, the effective hydrostatic pressure in the wellbore should be a little greater than or equal to that of the formation pressure.
Keep stable rheological property of the drilling fluid and avoid too great changes. It should be ensured that while drilling in the reservoir, all properties are always conformable to the requirements of reservoir protection and borehole stability.
Control tripping speed to avoid pressure surge and reduce contamination to the reservoir.
If it is required to weight the drilling fluid while drilling in the reservoir, use the weighting materials that can be acidized and dissolved.
34
11
Well Control Program
11.1 Selection of well control equipment
Select pressure ratings of the well control equipment according to the predicted formation pressure of Capella oilfield. The BOP selection program is shown in Table 11-1.
Spud No. 1
2
Table 11-1 Wellhead equipment and pressure testing requirments Testing requirements Pressure Allowable Test Name Type holding pressure pressure time drop (psi) (min) (psi) Simple wellhead Casing head
T 10 3/4×7-21(3000psi)
3000
≥10
100
Double ram
2FZ 28-21(3000psi)
3000
≥10
100
Choke/kill manifold
JG-21/YG-21(3000psi)
3000
≥10
100
Figure11-1 Wellhead equipment for 17 ½” hole section
35
Figure11-3 Wellhead equipment for 12 1/4″ hole section
Figure11-3 Wellhead equipment for 8 1/2″ hole section
36
Figure 11-3 21MPa choke/kill manifold 11.2 Requirements for BOP System Inspection and Testing
Requirements for testing well control equipment should conform to regulations of the Industrial Standards.
The BOP system includes BOPs, spool, choke/kill manifold, control system as well as liquid and gas lines. The tubular & tool company will be responsible for inspecting them piece by piece and making tests on them per requirements. When all pieces of equipment is qualified, fill in the qualification certificates, check the test records, sent the equipment to the rig site and hand them over to the drilling crew. All threads should be well protected during transportation to prevent them from damage.
The whole set of well control equipment will be tested in the well control workshop with fresh water. The ram BOP will be tested to rated pressure for at least 15 minutes. Pressure drop is allowed which should not exceed 100psi for the ram BOP.
Before drilling in the reservoir and after replacing the parts of well control equipment, make tests again with blanking plugs or pressure test plugs.
For testing the choke/kill manifold, the test pressure for all valves before the choke valve is the same as that for the ram BOP, and the test pressure for all valves after the choke valve is one pressure rating lower than that for the ram BOP. When testing each valve, all valves before and after it should be opened. Only after testing, can all valves return to required standard on/off position. Various internal blowout prevention tools should also be tested to rated working pressure. 37
11.3 Installation of the BOP System 11.3.1 Installing the wellhead components
Installing the spool. Holes in both sides of the spool should face both sides of the derrick door.
Installing ram BOP. Hand wheels of the manual locking device and the control rod should be located on both sides of the derrick door. Outlet of the side flange will face the direction of the derrick door. According to the size of the drilling tool to be used, install pipe rams with corresponding size. Put plates marking the types and sizes of the rams in the driller's console and in the remote control console in order to avoid wrong closing when blowout occurs. The manual locking device should be completely installed and well connected, and a plate marking the number of turns should be put on the hand wheel.
Relief manifolds will be installed on both sides of the derrick. The choke manifold will be installed on the right of the derrick (the drilling fluid outlet side), and the kill manifold will be installed on the left of the derrick. The relief/choke manifolds should be unblocked and be secured by cement base. Distance between the outlet of the manifold and the wellhead should be no less than 250ft.
After installation of the BOP system, adjust the crown block, the rotary table and the BOP stack. Centers of them should be aligned vertically and the offset should be no more than 0.4in. After adjustment, fix the BOP stack to the substructure with wire ropes.
11.3.2 Installing the control system
The remote control system (i. e. the accumulator) should be installed in a place about 100ft away from the wellhead, usually in the diagonal direction of the derrick. The remote control system should be installed in a skid-mounted prefabricated house. Ditches for draining water will be dug around the house. Oxygen bottles and combustibles are not allowed to be placed near the house.
The driller's console (i. e. the main control panel) will be installed on the drill floor close to the driller's working post for the convenience of the driller's operation.
Installing the pipelines. Before installing the hydraulic and air pipelines, each pipe should be cleaned by compressed air and be connected correctly as required. When connecting the air lines, the air valve and the air bypass valve of the air pump should be closed which can only be opened when they are to be used. All pipes should not be bent, broken and fired. They should be put in order and be well fixed. The control lines should not be used for welding and other purposes. 38
Connecting the electrical lines. When connecting the electrical lines, check again to see whether
electric parameters are correct. The electric power supply should be connected before the main switch on the rig site and be controlled with individual switches, so that when electric power of the rig site is turned off due to occurrence of a blowout, the use of the control system will not be affected. Electrical lines for the transceiver and long-distance search lights should also be connected before the main power supply.
11.3.3 Test-run of the BOP system
Before test-run, check all connections of the pipelines to see whether they are connected
correctly. Make test-runs with and without load respectively. Check leackage of all connections and
working conditions of all valves and pipelines. Solve the found problems in time after pressure is released. Open and close BOPs and relief valves twice by trial to see whether the switches are in good
working condition.
12
Operation Guidelines for Each Hole Section
12.1 Pre-spud preparation and site construction
The length of the front field is at least 150ft. Requirements for enough rig site area for special operations shall be satisfied.
Foundations for the derrick, diesel engines, mud pumps and the tanked circulating system shall be firmly fixed. Ensure high quality of the bottom construction and the height difference of basic planes is less than 0.12in.
3
The effective capacity of the mud reserve tank is no less than 8500ft and
water reserve tank
no less than 17500ft 3 should make use of plastic cloth to prevent water rush and seepage and meet application requirement. There should be no buildings except the dog house and other facilities within the overturning radius of the derrick.
Equipment should be installed flatly, stably, smoothly, completely, firmly, effectively and properly according to specifications to ensure the quality of installation. The crown block, rotary table and wellhead shall be calibrated to make sure that they are aligned, and the deviation should be no more than 0.4in.
Requirements of circuit installation: electric power for drill floor lamp, derrick lamp, engine
39
room lamp, pump room lamp, dog house lamp and dormitory lamp, search light, motor circuit and alarm circuit should be transmitted through nine separate power lines and be under centralized control in the dog house.
Lighting equipments of drilling fluid tank, derrick, engine room and pump room should be safety, explosion-proof, in good condition, no electrical leakage, no fire spark. Power house should be equipped with lightning arrester.
Search lights of well site and storage tank/pool should be enough to meet the lighting requirements for rig site operations.
3
The capability of water supply equipment shall be higher than 700ft /h. The maximum water supply capability of pool or tank shall be higher than 3500ft 3/h.
The ground surface under the drill floor and pump room or places around the rat hole and mouse hole must be faced with cement to avoid water seepage into the base which affects the base safety.
The ground surface under the drill floor, engine room and pump room should be higher than the rig site surface and available with external drainage. Ditches shall be dug for draining off water and be connected to the sewage pit whose effective volume is no less than l00m 3.
The well site should be flat and smooth. All the drill tools should be steadily placed on pipe rack. Disordered placement is strictly prohibited to avoid drill tool accidents caused by surface damage.
Before spud, all the power and mechanical equipments should be tested run for 2h with load. Ensure that oil&water&gas lines are sealed and the switches of valve are flexible without leaking. Do not spud until all things are qualified.
Prior to drilling operation, the drilling crews should be convened to understand clearly the geologic and engineering design and complete all preparatory work with definite guiding ideology.
17 1/2″ hole section
Ensure that the 26″ hole is vertical. WOB increases with the weight of drill collars in the given range. Trip out and measure the hole angle. Drilling operation is not allowed until successful measurement of the hole angle is achieved.
Run in 13 3/8″ casing and cementing a.
When running casings, threads of the casings should be tightened to specified torque. Prohibit thread alternating, undertonging and electric welding between threads. If there is a 40
△ symbol at the pin end of casing, screw on the thread of the casing to the bottom line of the △ symbol and fill up casing with drilling fluid. b. When running casings, bind float shoe, float collar and intermediate casing with thread gum. If thread gum is unavailable, joint them with electric welding. c.
Cement slurry must return to surface.
Properly select BHA. Check the weight indicator. Start drilling with light WOB and keep the borehole vertical. The hole angle should be smaller than 0.5º, otherwise take measures to straighten the hole.
Add stabilizers with is matched with the bit diameter at the upper part and lower part of the first drill collar to ensure a regular borehole and successful casing job.
Make up connections quickly, make good control of running in speed and don’t start the pump too fast. Drill string should be reciprocated when circulation stops due to some reasons to prevent pipe-sticking. The time drill string stay in hole should not exceed 5min.
12.3 12 1/4″hole section
Safety measures a.
Check the equipment in advance to ensure continuous operation and avoid interrupted operation.
b. Feed WOB evenly, drill the soft and hard interface successively and make up connections quickly. Keep the pump working for a long time (start early and stop late. Variation of flow rate should be smooth. c.
The drill bit should contact the bottom hole steadily. Make a survey before tripping out of the bit or after continuous footage of 500ft for each bit. If the hole angle is a bit larger, replace the current BHA with deviation-correction BHA.
d. Make good control of tripping speed. Find drags or pipe-sticking timely and treat them in accordance with operation specification. e.
Drilling fluid should be maintained and treated in accordance with the design requirements. Corresponding LCM should be reserved on the rig site. Enough high quality drilling fluid should be stored at site according to design requirements.
f.
Prevent anything from falling into the borehole.
Raise the mud inhibitive capability, mud must have good functions of hole wall protection and hole cleaning.
In drilling this section, flow rate should be higher than 700gpm, pay more attention of cuttings bed, recommended short tripping or backreaming per 24hours. Precaution the differential 41
pressure sticking pipe or casing.
Prepare the casing accessories and cementing tools to realize cementing above the top of screen.
One kind of BHA to realice trajectory of building up, turning direction, holding on and horizontal sections
Bit bouncing, deviation trend, lost circulation and drill tool accidents are problems encountered in drilling operation. Therefore, appropriate drilling technology should be worked out in view of the feature of the drilling interval. The key concerns are to keep a vertical borehole, drill rapidly and do well in near-balanced drilling and trajectory controlling.
Strengthen management of equipments especially the drill pump. Normal operation of drilling equipment should be assured and prevent operations from being interrupted frequently.
Before the drill collar drilling out the surface casing shoe, WOB should be controlled in the range from 10klb to 18klb. The second gear should be used for drilling. After the drill collar drilled out the casing shoe, WOB should be gradually increased to 60klb to 80klb. Avoid borehole deviation and ensure the wellbore quality.
Survey the hole angle before tripping out or after drilling every 1000m to 1500ft in order to monitor and follow the hole trajectory timely.
During drilling process, pay attention to the downhole situation. If borehole wall sloughing is encountered, adjust drilling fluid properties timely to ensure normal downhole operation. Prevent downhole problems and accidents caused by borehole wall sloughing and lost circulation.
Before spudding, all equipments especially the electric circuit part and well control equipment shall be inspected completely. Strictly perform the blowout prevention drills to achieve the control of well head in each shift. At the same time, engineering and geological technical personnel should inform drilling crews of technology details for drilling the oil and gas reservoir. The post responsibility system should be implemented.
Drill tools should be strictly managed. Carefully check the drill tools to be run in hole. Persist in switching within the drillstring and check thread alternating to avoid drill tool accidents.
Operators should strengthen the sense of responsibility and observe and analyze down hole situation in time. In case the pump pressure drops, stop drilling to analyze the reason. If no reason can be searched out, put out of hole and check.
Persist in making good use of solids control system. Add appropriate amount of lubricant to control the frictional coefficient of mud cake in the designed range. The time of drill tool being static in hole should not exceed 3min to avoid pipe-sticking.
Strictly inspect the rig tools. Prevent anything from falling into the borehole to avoid 42
pipe-sticking. 12.4 8 1/2" hole drilling
Solids should be controlled as lower as possible.
Change mud by new clean mud, reduce the mud weight and other properties to design
Pay more attention to the differential pressure sticking pipe and casing
Adopt the shielding & temporary plugging technique to prevent harmful substances from invading the reservoir. Prepare different types and parcels of LCM on the location.
In drilling this section, flow rate should be higher than 500gpm, especialy in horizontal section, pay more attention of cuttings bed, recommended short tripping or backreaming per 24hours. Precaution the differential pressure sticking pipe or casing.
MWD/LWD tools should be in good condition. Before running in hole test them carefully on the surface or in shallow depth of the hole.
The dogleg should be controlled within permit rang. Real well trajectory should follow the design one and keep the trajectory smooth.
12.5 Precautions for drilling hazards 12.4.1 Leak protection
During drilling process, adjust drilling fluid properties. Select the designed lower range value of drilling fluid density if possible to keep near-balanced drilling.
Before encountering the leakage interval, lost circulation materials should be prepared in advance. Condition drilling fluid properties in accordance with design requirements and prepare to add lost circulation materials at any time.
When running in hole, the running speed should be under control. After drill to 1500ft, auxiliary brake should be used. The time for running in a stand should not be less than 30s to prevent inducing drilling fluid loss because of the excessive high pressure surge caused by the excessive high speed.
If weighting operation is needed with active oil&gas during drilling process, density should be gradually increased according to the circulation. It should be increased 0.4 to 0.8 ppg for each circulation cycle until the overflow disappears. Prevent downhole situation becoming complex caused by blindly weighting operation.
During running in process, circulate drilling fluid in stages. Running in to the bottom directly and then starting pump to circulate is strictly prohibited. Start pump with a low flow rate to 43
push through the hole, and then pump with normal flow rate. Strictly prevent leakage caused by opening pump too fast.
Designated personnel shall observe the changes of drilling fluid level at all times. In case lost circulation occurs both when drilling in and running in, pull out of hole at once if leakage volume up to 180ft 3. Continuously pump drilling fluid to the hole and prepare for loss-curing.
12.4.2 Well trajectory control
Equipment should be installed flatly, stably, smoothly, completely, firmly, effectively and properly according to specifications to ensure the quality of installation. The crown block, rotary table and wellhead shall be calibrated to make sure that they are aligned, and the maximum allowable deviation should be no more than 0.4in.
Make sure that the weight indicator, parameter recorders and pressure gages are sensitive, accurate and in good condition.
Before running in MWD/LWD tools, they need to be tested on the surface, when running in hole in shallow position, do test again to ensure they are in good condition.
When drilling in surface layer, keep balance of the drilling hose. Drill with low WOB. The hole deviation angle should be less than 0.5°. Well straightening operation should be performed if hole deviation angle is too large.
When maintaining equipments or treating drilling fluid, reciprocate the drill string by a wide margin to circulate drilling fluid. Rotational circulation should not be in a position with a high flow rate for a long time to avoid deviation caused by a large hole.
A new bit should not be drilled to the bottom without break. Start pump with low flow rate when near the bottom. Start rotary table with bottom gear for slowly running to bottom. After running the bit with 10-40klb WOB about half an hour, WOB should be gradually increased to normal value.
While drilling in, strictly control the borehole quality to meet the requirments of designed well profile.
12.4.3 Pipe-sticking prevention
When drilling horizontal section, differential pressure sticking pipe and casing will easily happen, the efficient prevention ways should be taken.
Short tripping and backream need to be used every 24 hours or 800ft to keep the hole in good condition. When the drill string isn’t in the hole for a long, mud cake will become thicker a nd sticker. In this situation, pay more attention to pipe sticking when run in hole with drill string. 44
For hole cleaning, circulation time should be more than two bottoms up. In high deviation hole, cuttings often settle down, flow rate should be kept as high as possible, meanwhile, raise the rotating speed properly. Drill string in static in the hole is no more than 3 minutes whatever operations carry out.
Once the differential pressure sticking happen, try to keep circulation at any time. Prepare release agent and soak the pipe as quickly as possible. To reduce differential pressure the weight of release agent need to be as low as possible.
Before running in E-logging tools or casing, ream the hole thoroughly. Rock bit and slick collars is the best string used to ream the hole. Increase flow rate as possible; observe the cuttings return till no cuttings on the shale shaker.
Don’t stop running in casing too much time whatever operations carry out. Don’t fill in mud when casings are running in horizontal section. Run casing to the bottom as quickly as possible, and then circulate mud for cementing.
Well trajectory need to be controlled in good profile, high dogleg will produce high resistance. Montor well profile to evaluate this resistance; take the right way to run casing to the bottom.
Prior to spudding in, rig equipments, well head, instruments should be inspected by relevant personnels from company. Equipment should be installed flatly, stably, smoothly, completely, firmly, effectively and properly according to specifications. Drilling operation can not be performed until meet the acceptance requirements.
Inspection requirements before every spudding in a.
The driller should inspect wear information of the drilling line. Slip and cut off the drill line if there are 12 broken wires in a pitch of strand.
b. The driller should carefully check the brake system, fixation condition at the both end of drilling line and the regulating situation of the brake band adjusting screw. c.
Inspect whether the weight indicator is accurate, whether the hang weight conform to the actual weight of drill tools, whether the curve of auto recorder is clear and whether have abnormal records.
d. Carefully check whether gas circuit and crown block saver are reliable.
Strengthen the movement of drill string. The time drill string being static in hole should not exceed 3min. If drilling operation can not be performed, move drill string up and down by a wide margin.
If drill string can not be moved because of equipment failure, 2/3 of the hang weight should be pushed slowly to the bottom hole. Repair the equipment as soon as possible. After repairing the equipment, circulate drilling fluid to pull out of hole rather than drill ahead. 45
Make up connections quickly. Especially at the time of faster penetration, the time make a connection should not be more than 3min. Pump stop time should be cut down (stop pump late and start pump early) to reduce the settle sand.
Condition drilling fluid before drilling in. Circulate with high flow rate and pull out of hole after at least 2 bottoms up. Running operation to hole bottom should not be performed in one time. Start pump to circulate stepwise and run in hole until normal. Do not force to pull up or run in with too more weight for a tight hole over 225klb. Make connection with a Kelly, start pump to push through the hole and circulate to normal, then go on tripping.
When drilling in, if pump pressure raise, hang weight drop, returned drilling fluid volume reduce and rotary table reverse occur, stop drilling ahead or making connections. After pulling drill tool to normal interval, borehole should be returned to normal by flushing, making wiper trip and reaming to precede operation.
In water swelling formation or unconsolidated formation, condition drilling fluid properties and control water loss to avoid drags and stuck pipe caused by tight hole, hole sloughing or thicker mud cake.
Footage of every bit should not be more than 1000ft. Otherwise, make short trip to ensure a smooth hole. The length of trip interval should be longer than that of drilling interval to prevent drill pipe sticking in mudstone due to tight hole.
If pump pressure drop is found when drilling in, stop drilling ahead to find the reason. If any problem can not be found on surface, pull out of hole to inspect drill tools.
During drilling process, if drill time decreases, bit bouncing, pump pressure raises and pipe-sticking when picking up drill tool are found, stop drilling at once to condition properties of drilling fluid. At the same time, move drill tool up and down for long distance with high speed rotation, increase the circulating capacity to remove ballings on bit or stabilizer.
If bit balling occurs, the bottom gear should be used for tripping out. Fill up drilling fluid continuously. If drilling fluid can not be filled in the annular space, fill in from drill tools. The tripping speed should be not too high to prevent down hole problems caused by swabbing.
Prevent anything such as tools, screw and dies from falling in hole while operating at the wellhead. While the well is empty, bit box can be used to cover the wellhead.
Drill tools to be run in hole should be carefully inspected according to regulation. Drill tool should not be run in hole if unqualified.
46
13
Wellhead equipment for completion
13.1 Casing head specification
T 9 5/8″ ×7″ -21 (3000psi). The last casing head should be below the ground for the convenience of rig quick moving. Consider about the top level of casing head, it must be keeped as the same level as ground 13.2 Wellhead protection
Keep the cellar clean.
The casing head must be kept horizontal with a level ruler. After installation of the wellhead, tighten the four conners of the well head with guys and align the casing head with the center of the rotary table.
Two sets of casing head wear-proof casing must be available. Install one set during operation and check and replace it periodically. Supplement immediately if no backup equipment is available.
All flange and handwheel must be made up to the specified torque, wellhead cap must be installed before installation of the the Christmas tree.
Carry out sealing compound injection and pressure test operation in accordance with regulations to ensure reliable sealing.
13.3 Completion requirements
Drift the hole to the artificial hole bottom with standard drift diameter gauge and testing drift diameter gauge.
Tally the tubing being run into the hole and make records based on running sequence.
There should be no oil, gas and water invasion into the casing or leaking out of the casing after completion.
Upper end surface of the top flange (lower end surface of the tubing spool) for casinghead hanging the production casing can not be 1.3ft higher than the surface. If its position is excessive low, it shall be adjusted by using lift nipple. It must be adjusted while running in 7 ″ casing. The 7″ casing hanger shall be seated on the top of the lifting nipple. The Christmas tree shall be installed uprightly and firmly in accordance with relevant regulations.
The well site shall be smooth and neat withou mud, oily dirt and water accumulation. The rat hole and mouse hole must be backfilled and tamped, and a warning sign shall be set up. If mud, fresh water and mud materials are needed for testing, the drilling company is responsible to deliver the field stocks to the test company. In principle, the materials required in the testing 47
program must be managed by the test company after testing. Except for the materials specified in the agreement between the drilling company and the test company, the other materials out of the testing program must be managed by the drilling company after testing.
The well completion data documents shall be complete, accurate and tidy, and shall be delivered before the specified date.
The casing head shall be fully installed with pressure gauge and outgoing pipeline (fixed firmly). The cementing quality is good with no oil&gas channeling and no pressure in the annulus.
The following working procedures shall be done during well completion period: 1. Run in all of production casing and then carry out cementing.The cement job must be qualified. The production casing string was successively seated and hanged on the casing head with good sealing. Inject sealing compound and perform pressure test. The pressure test must be qualified. No fluid invasion into the casing or leakage out of the casing.(The above mentioned jobs will be confirmed by signatures of drillin crew leader and supervisor). 2. Drift the casing with test drift diameter gauge. It shall be confirmed by signatures of drilling crew leader and supervisor. 3. Run the drill string to the artificial hole bottom. Displace the hole with fresh water, then stabilize for 24h, no overflow occurs, circulate and observe possible oil, gas and water invasion. The pressure test is qualified which confirms the success of the cement job and good isolation of the casing. Displace the hole with mud which can control all the pay zones. 4. The well tested with the former rig will be delivered to the test company. 5. The following work will be done for the well tested with another rig: a.
Pull drill string out of hole and fill up mud simultaneously (no overflow).
b. Disassemble BOP stack. c.
Pull the production casing out of the tubing hanger or cut it from 1ft above the top flange of the casing head (no deformation on the end surface, no junks left in the hole).
d. Clean the top flange of the casing head, tubing hanger thread, dope corrosion inhibiting oil on the tubing hanger thread, daub grease in the steel ring groove or inject engine oil fully. e.
Cover strawhat-type protective cap (keep the lower edge at the same level with the top flange of the casing head), secure the foure corners with four screws.
f.
Clean the casing head, cellar. Install all the valves (double valves for each side of 48
casing head), stopcock, pressure gauge. The bleeding lines for various casing heads shall be installed and fixed firmly. g. Deliver the well to the test compmay when the rig has been moved from the well site. Provide complete documents which fully demonstrate the well conditions. Perform pressure test and cofirm the success of the test with the presence of both parties and carry out a written transfer procedures.
14
HSE requirements
14.1 Basic requirements
Implement the laws, regulations, standards and systems on safety, environment protection, professional health, fire fighting, emergency solutions,etc, which are established by the resource country, cocal government and Sinopec.
Companies engaged in development of oil ang gas resources shall obtain the ″ Safety Production License″ and establish the HSE management system which involves sigle well safety and environment risk analysis. Peform HSE check and drill. Provide sufficient pollution-control equipment and realize standard pollutant discharge.
Drilling crew shall establish a HSE leadership group with clear working duties. The follwing ideas shall be followed by the drilling crew: safety first, precaution crucial, all staff participation, comprehensive management, environment improvement, health protection, scientific management, sustainable development. Pursue the goal of no accident, no damage to human health, any environment damage and first-class HSE achievement in China.
Drilling crew shall hold the effective certificates in accordance with the relevant regulations of the resource country and local government.
The drilling crew shall provide effective inspection reports or certificates and signs for the following equipment: safety equipment and safety accessories, special equipment, measurement instruments, H2S detection device, derrick, etc.
Drilling crew qualification and personnel requirements:
The toolpusher and HSE management personnel shall hold ″ Safety Production Management Certificate″ ; a.
All the personnel shall hold HSE operation certificates;
b. Special operating personnel (electrical operation, metal welding, boiler operator, crane operator, etc.) shall hold ″ Special Operation Certificate″ ; c.
Toolpushers, drilling engineer (technician), security personnel, stud driller, driller, assistant 49
driller, derrickman shall hold effective ″ Driller’s O peration Certificate″ and ″ Well Operation Certificate″. d. Cooks shall hold effective health certificates. e.
All the people who work in a place where H 2S may exist shall accept H 2S traninning and obtain ″ H2S Protection Technique Traninning Certificate″ .
Incorporate in a single system the observations made and reported by all the service companies.
Ongoing campaigns and incentives for reporting of unsafe conditions and actions
Establish mechanisms focused on example-based change in mentality.
Effective procedure for analysis, tracking and closing of reports.
Tracking and daily report of RIT cards to operations coordinator to guarantee effective closing.
Stricter control at supervisory levels in respect to observance of PPE usage policies
Strict tracking of reprimands for failure to comply with use of PPE.
14.2 Liquid and solids waste managment program
In accordance with the Environmental management plan a zodme area will be available in the location to mix and dispose water-based cuttings.
The solids and liquid waste management program is intended to reduce waste generation by reutilizing resources. This may be accomplished through proper management of the solid control equipment, where centrifugal decanters play a very important role. Moreover, water must be managed on the basis of a culture aimed on saving and recycling.
14.3 Waste management objects (HSE)
Full compliance with parameters for disposal of solids and liquids
Reduction of costs on account of drilling and/or completion fluids and industrial water recycling
Optimum use of water-based cutting disposal zones
Full compliance with water disposal parameters for discharge or irrigation
Full compliance with parameters for disposal of oil recovered from batteries
Recovery of associated fluids in cuttings and recycling in water
No environmental damages
Perfect presentation and mechanical conditions of equipment
Skilled and unskilled personnel, trained on operations and HSEQ 50
Involvement in planning and evaluation of performance indicators .
15. Logistic issues
Tracking of observance of speed limits
Verification of observance of escort vehicles usage policies
Mandated use of secondary roads skirting entry to Los Pozos township
Establishment of a single procedure for entry and presence of persons at the location. Strict compliance on the part of access controllers.
Require prior information on movement of personnel and/or tools.
Establishment and tracking of the calendar of managerial visits (Coordinators).
Verify continuity in monitoring of operational parameters with drilling equipment.
Establishment of per-capita consumption goals to optimize water use.
Establish mechanisms for water reuse
Verification of proper storage.
Chemical contamination incident (direct exposure).
Good labeling of chemicals in resistant materials
Drill in A Sand in different phase that conglomerate.
Move waste collection points to points that are not at the entry to locations
Insist on recycling campaigns
Employ sensors for same parameters taking readings from different points.
Keep parameter monitoring equipment even for completion operations
Analyze and establish mechanisms for proper shift handover
Require and review inspection certificates of all tools reaching the well
Tracking of the inspection and maintenance calendar for equipment and tools used in the operation.
16
Request and keep at the field a backup of tools and spares with a significant chance.
Requirements for drilling information report
Daily drilling report
Daily mud report
Survey report
Directional daily report 51
Cementing operation report
Daily mud logging report
Wireline logging report
Down hole troubles and accidents curing reports
Final drilling report
17
Drilling cycle forecast Table 17-1 Drilling schedule
52
