1. MIRU SL2. Hold safety meeting. Make gauge ring run to PBTD est. 7850’,
send results to Engineering.3. RDMO SL4. If approval to proceed, MIRU completion rig5. Make bit and scraper run to PBTD6. TIH with open ended workstring, displace hole with 9.8 ppg KCL
completion fluid.Note: expected reservoir pressure is 3600 psi at 7500’. 9.8 ppg fluid will provide a 222 psi OB.
7. Test casing to 5000 psi for 15 minutes8. MIRU EL unit, hold explosives safety meeting and conduct JSA.
RIH and perforate 7500-7570’ (reference OH log dated Nov 9, 2016) with 4 5/8” gun loaded 6 spf, 60 deg phasing,32 gm RDX charges
9. POOH with guns, check that all shots have fired, if not, inform Engineering
10. Monitor hole conditions for 4 hours, report any fluid loss or pressure build up
11. If well stable, TIH with completion string consisting of MS WL reentry guide, XN landing nipple, model MJG mechanical retrievable packer, sliding side door, and 2 7/8” 6.5 #/ft tubing. Set packer at 7400’.
12. MIRU SL, set plug in lower XN nipple, test tubing to 5000 psi for 15 min. RDMO SL.
13. Test backside to 5000 psi for 15 min.14. Install BPV, ND BOPs, NU 5000 psi tree and flowlines, pull BPV,
turn well over to Production15. If required, use lease gas to rock well in, open on 16/64 ck.
Model MJG packer set at 7400’
Perforations 7500’-7570’ MD. Note, top sand at 7500’, bottom sand at 7610’.
WEG at 7410’
XN at 7405’
SSD at 7390’
2 7/8” 6.5 ppf API EUE N-80 tubing
Sketches and Procedures – Initial Completion
Pre-sketch Proposed SketchProcedure
Well left with 10 ppg mud in casing
when drilling rig moved off location.
7” 32#/ft casing run to 8000’ with PBTD at 7850’
1. MIRU SL2. Hold safety meeting. Make gauge ring run to PBTD est. 7850’,
send results to Engineering.3. RDMO SL4. If approval to proceed, MIRU completion rig5. Make bit and scraper run to PBTD6. TIH with open ended workstring, displace hole with 9.8 ppg KCL
completion fluid.Note: expected reservoir pressure is 3600 psi at 7500’. 9.8 ppg fluid will provide a 222 psi OB.
7. Test casing to 5000 psi for 15 minutes8. MIRU EL unit, hold explosives safety meeting and conduct JSA.
RIH and perforate 7500-7570’ (reference OH log dated Nov 9, 2016) with 4 5/8” gun loaded 6 spf, 60 deg phasing,32 gm RDX charges
9. POOH with guns, check that all shots have fired, if not, inform Engineering
10. Monitor hole conditions for 4 hours, report any fluid loss or pressure build up
11. If well stable, TIH with completion string consisting of MS WL reentry guide, XN landing nipple, model MJG mechanical retrievable packer, sliding side door, and 2 7/8” 6.5 #/ft tubing. Set packer at 7400’.
12. MIRU SL, set plug in lower XN nipple, test tubing to 5000 psi for 15 min. RDMO SL.
13. Test backside to 5000 psi for 15 min.14. Install BPV, ND BOPs, NU 5000 psi tree and flowlines, pull BPV,
turn well over to Production15. If required, use lease gas to rock well in, open on 16/64 ck.
Model MJG packer set at 7400’
Perforations 7500’-7570’ MD. Note, top sand at 7500’, bottom sand at 7610’.
WEG at 7410’
XN at 7405’
SSD at 7390’
2 7/8” 6.5 ppf API EUE N-80 tubing
The well in the current (original) condition.
For New Completion: This is generally the way the drilling rig left the well, so it is usually simple. Note that by tradition we do not show other casing strings nor the wellhead. But these can be important, so do not forget that other casing stings exist in the well and that there is something on the top.
For Workover: This sketch may be very complicated, with lots of equipment already in the well!
Design Process for Completion and Workovers Core ═════════════════════════════════════════════════════════════════════════
1. MIRU SL2. Hold safety meeting. Make gauge ring run to PBTD est. 7850’,
send results to Engineering.3. RDMO SL4. If approval to proceed, MIRU completion rig5. Make bit and scraper run to PBTD6. TIH with open ended workstring, displace hole with 9.8 ppg KCL
completion fluid.Note: expected reservoir pressure is 3600 psi at 7500’. 9.8 ppg fluid will provide a 222 psi OB.
7. Test casing to 5000 psi for 15 minutes8. MIRU EL unit, hold explosives safety meeting and conduct JSA.
RIH and perforate 7500-7570’ (reference OH log dated Nov 9, 2016) with 4 5/8” gun loaded 6 spf, 60 deg phasing,32 gm RDX charges
9. POOH with guns, check that all shots have fired, if not, inform Engineering
10. Monitor hole conditions for 4 hours, report any fluid loss or pressure build up
11. If well stable, TIH with completion string consisting of MS WL reentry guide, XN landing nipple, model MJG mechanical retrievable packer, sliding side door, and 2 7/8” 6.5 #/ft tubing. Set packer at 7400’.
12. MIRU SL, set plug in lower XN nipple, test tubing to 5000 psi for 15 min. RDMO SL.
13. Test backside to 5000 psi for 15 min.14. Install BPV, ND BOPs, NU 5000 psi tree and flowlines, pull BPV,
turn well over to Production15. If required, use lease gas to rock well in, open on 16/64 ck.
Model MJG packer set at 7400’
Perforations 7500’-7570’ MD. Note, top sand at 7500’, bottom sand at 7610’.
WEG at 7410’
XN at 7405’
SSD at 7390’
2 7/8” 6.5 ppf API EUE N-80 tubing
A series of chronologically organized steps that the operations team should follow to get to the proposed sketch.
Generally involves placing items into the well or pulling them out of the well, and doing so in such a manner that the reservoir pressure is always contained – no unwanted flow of reservoir fluids to the surface!
Sketches and Procedures: Terminology
1. MIRU SL2. Hold safety meeting. Make gauge ring run to PBTD est. 7850’, send
results to Engineering.3. RDMO SL4. If approval to proceed, MIRU completion rig5. Make bit and scraper run to PBTD6. TIH with open ended workstring, displace hole with 9.8 ppg KCL
completion fluid.Note: expected reservoir pressure is 3600 psi at 7500’. 9.8 ppg fluid will provide a 222 psi OB.
7. Test casing to 5000 psi for 15 minutes8. MIRU EL unit, hold explosives safety meeting and conduct JSA. RIH
and perforate 7500-7570’ (reference OH log dated Nov 9, 2016) with 4 5/8” gun loaded 6 spf, 60 deg phasing,32 gm RDX charges
9. POOH with guns, check that all shots have fired, if not, inform Engineering
10. Monitor hole conditions for 4 hours, report any fluid loss or pressure build up
11. If well stable, TIH with completion string consisting of MS WL reentry guide, XN landing nipple, model MJG mechanical retrievable packer, sliding side door, and 2 7/8” 6.5 #/ft tubing. Set packer at 7400’.
12. MIRU SL, set plug in lower XN nipple, test tubing to 5000 psi for 15 min. RDMO SL.
13. Test backside to 5000 psi for 15 min.14. Install BPV, ND BOPs, NU 5000 psi tree and flowlines, pull BPV, turn
well over to Production15. If required, use lease gas to rock well in, open on 16/64 ck.
MIRU – move in and rig upSL – slick line unitEL – electric lineRDMO – rig down and move offPBTD – plug back total depthTIH – trip in hole; usually jointed pipeTOOH – trip out of hole; usually jointed
pipeRIH – run in hole, often not pipe
(e.g., wireline or coiled tubing)POOH – pull out of holeND – nipple down (unfasten bolts;
usually for a BOP or tree)NU – nipple up
Design Process for Completion and Workovers Core ═════════════════════════════════════════════════════════════════════════
1. MIRU SL2. Hold safety meeting. Make gauge ring run to PBTD est. 7850’, send results
to Engineering.3. RDMO SL4. If approval to proceed, MIRU completion rig5. Make bit and scraper run to PBTD6. TIH with open ended workstring, displace hole with 9.8 ppg KCL
completion fluid.Note: expected reservoir pressure is 3600 psi at 7500’. 9.8 ppg fluid will provide a 222 psi OB.
7. Test casing to 5000 psi for 15 minutes8. MIRU EL unit, hold explosives safety meeting and conduct JSA. RIH and
9. POOH with guns, check that all shots have fired, if not, inform Engineering10. Monitor hole conditions for 4 hours, report any fluid loss or pressure build
up11. If well stable, TIH with completion string consisting of MS WL reentry
guide, XN landing nipple, model MJG mechanical retrievable packer, sliding side door, and 2 7/8” 6.5 #/ft tubing. Set packer at 7400’.
12. MIRU SL, set plug in lower XN nipple, test tubing to 5000 psi for 15 min. RDMO SL.
13. Test backside to 5000 psi for 15 min.14. Install BPV, ND BOPs, NU 5000 psi tree and flowlines, pull BPV, turn well
over to Production15. If required, use lease gas to rock well in, open on 16/64 ck.
Pre-sketch Proposed Sketch
Model MJG packer set at 7400’
Perforations 7500’-7570’ MD. Note, top sand at 7500’, bottom sand at 7610’.
WEG at 7410’
XN at 7405’
SSD at 7390’
2 7/8” 6.5 ppf API EUE N-80 tubingThis is what the completion engineer wants to
get to – the final state of the well. There is a lot of engineering that goes into this sketch; which is the overall subject of this skill module. Consider for now several questions:
Why perforate that interval? Why just perforate, and not frac or gravel
pack? Why run that packer and that size tubing? Why run tubing at all?
Design Process for Completion and Workovers Core ═════════════════════════════════════════════════════════════════════════
gauge ring run to PBTD est. 7850’, send results to Engineering. Note any sand or obstructions inside the tubing.
3. Make up lock mandrel with pressure gauges for XN landing nipple at 7405’.
4. Run lock mandrel and set in XN nipple, hang off gauges, pull running tool.
5. RDMO SL
Pre Sketch Proposed SketchProcedure
Sketches and Procedures – Intervention
1. MIRU SL2. Hold safety meeting. Make
gauge ring run to PBTD est. 7850’, send results to Engineering. Note any sand or obstructions inside the tubing.
3. Make up lock mandrel with pressure gauges for XN landing nipple at 7405’.
4. Run lock mandrel and set in XN nipple, hang off gauges, pull running tool.
5. RDMO SL
Pre Sketch Proposed SketchProcedure
2 7/8” 6.5 ppf API EUE N-80 tubing
SSD at 7390’ Model MJG packer set
at 7400’ XN at 7405’ WEG at 7410’ Perforations 7500’-
7570’ MD. Note, top sand at 7500’, bottom sand at 7610’.
2 7/8” 6.5 ppf API EUE N-80 tubingSSD at 7390’Model MJG packer set at 7400’XN at 7405’Lock mandrel with pressure gauges hung off Feb 15 ‘17WEG at 7410’Perforations 7500’-7570’ MD. Note, top sand at 7500’, bottom sand at 7610’.
What is going to be done?
Design Process for Completion and Workovers Core ═════════════════════════════════════════════════════════════════════════
1. MIRU SL2. Hold safety meeting. Make gauge ring run to PBTD
est. 7850’, send results to Engineering.3. RDMO SL4. If approval to proceed, MIRU completion rig5. Install BPV, remove tree, NU BOPs6. TIH with open ended workstring, displace hole with
9.8 ppg KCL completion fluid.Note: expected reservoir pressure is 3600 psi at 7500’.
9.8 ppg fluid will provide a 222 psi OB. 7. Test casing to 5000 psi for 15 minutes8. MIRU EL unit, hold explosives safety meeting and
conduct JSA. RIH and perforate 7500-7570’ (reference OH log dated Nov 9, 2016) with 4 5/8” gun loaded 6 spf, 60 deg phasing,32 gm RDX charges
9. POOH with guns, check that all shots have fired, if not, inform Engineering
10. Monitor hole conditions for 4 hours, report any fluid loss or pressure build up
11. If well stable, TIH with completion string consisting of MS WL reentry guide, XN landing nipple, model MJG mechanical retrievable packer, sliding side door, and 2 7/8” 6.5 #/ft tubing. Set packer at 7400’.
12. MIRU SL, set plug in lower XN nipple, test tubing to 5000 psi for 15 min. RDMO SL.
13. Test backside to 5000 psi for 15 min.14. Install BPV, ND BOPs, NU 5000 psi tree and
flowlines, pull BPV, turn well over to Production15. If required, use lease gas to rock well in, open on
16/64 ck.
Pre Sketch Proposed Sketch
Sketches and Procedures – Workover
1. MIRU SL2. Hold safety meeting. Make gauge ring run to PBTD
est. 7850’, send results to Engineering.3. RDMO SL4. If approval to proceed, MIRU completion rig5. Install BPV, remove tree, NU BOPs6. TIH with open ended workstring, displace hole with
9.8 ppg KCL completion fluid.Note: expected reservoir pressure is 3600 psi at 7500’.
9.8 ppg fluid will provide a 222 psi OB. 7. Test casing to 5000 psi for 15 minutes8. MIRU EL unit, hold explosives safety meeting and
conduct JSA. RIH and perforate 7500-7570’ (reference OH log dated Nov 9, 2016) with 4 5/8” gun loaded 6 spf, 60 deg phasing,32 gm RDX charges
9. POOH with guns, check that all shots have fired, if not, inform Engineering
10. Monitor hole conditions for 4 hours, report any fluid loss or pressure build up
11. If well stable, TIH with completion string consisting of MS WL reentry guide, XN landing nipple, model MJG mechanical retrievable packer, sliding side door, and 2 7/8” 6.5 #/ft tubing. Set packer at 7400’.
12. MIRU SL, set plug in lower XN nipple, test tubing to 5000 psi for 15 min. RDMO SL.
13. Test backside to 5000 psi for 15 min.14. Install BPV, ND BOPs, NU 5000 psi tree and
flowlines, pull BPV, turn well over to Production15. If required, use lease gas to rock well in, open on
16/64 ck.
Pre Sketch Proposed Sketch
2 7/8” 6.5 ppf API EUE N-80 tubing
SSD at 7390’ Model MJG packer
set at 7400’ XN at 7405’ WEG at 7410’ Perforations 7500’-
7570’ MD. Note, top sand at 7500’, bottom sand at 7610’.
2 3/8” 4.7 ppf J-55 tubing SSD at 7390’ Model XYZ packer set at 7150’ XN at 7155’ WEG at 7160’ Perforations 7200 – 7230 MD.
Note, top sand at 7200’, bottom sand at 7230’.
Cmt Retainer at 7400 Perfs squeezed with cement
through cement retainer Perforations 7500’-7570’ MD.
Design Process for Completion and Workovers Core ═════════════════════════════════════════════════════════════════════════
The engineer will use the morning reportsto develop a final post well sketch
Morning ReportsFinal Post Well Sketch
Morning Reports
Morning ReportsA report that the operations team prepares daily, usually in the morning (6 AM is a typical report time).
These reports are industry standard. Globally, every company uses something similar. The format and content may vary slightly, but all contain similar information.
Reading these reports is important for most disciplines and managers involved in upstream activities.
What does your company use as a morning report tool?
Design Process for Completion and Workovers Core ═════════════════════════════════════════════════════════════════════════
This is an example of a morning report. These morning reports are fairly standard in that much of this similar information is conveyed in a daily completion or work over morning report. Your company’s format might be slightly different.
The Well Information section
describes the well, where it is
located, the casing
configuration, and the report
date.
The Contact Information
section tells us about the rig
doing the work, and the
primary contact – the company
representative on site.
The Cost Information section
tells us about the costs – VERY
IMPORTANT – what is the daily
cost, the cumulative cost, and
the AFE cost (what was
planned).
The Daily Operations section
tells us about the daily
operations – VERY IMPORTANT
– there is usually a summary, a
forecast, and a 24‐hour detailed
log. We might find information
on fluids, pressures, and
incidents here as well.
The Perforations/Stimulation
Summary section has details of
perforation and stimulation –
not all reports have this
section, but it is common
among the UR community.
Design Process for Completion and Workovers Core ═════════════════════════════════════════════════════════════════════════
1. MIRU SL2. Hold safety meeting. Make gauge ring run to PBTD est. 7850’, send results
to Engineering.3. RDMO SL4. If approval to proceed, MIRU completion rig5. Make bit and scraper run to PBTD6. TIH with open ended workstring, displace hole with 9.8 ppg KCL
completion fluid.Note: expected reservoir pressure is 3600 psi at 7500’. 9.8 ppg fluid will provide a 222 psi OB.
7. Test casing to 5000 psi for 15 minutes8. MIRU EL unit, hold explosives safety meeting and conduct JSA. RIH and
9. POOH with guns, check that all shots have fired, if not, inform Engineering10. Monitor hole conditions for 4 hours, report any fluid loss or pressure build
up11. If well stable, TIH with completion string consisting of MS WL reentry
guide, XN landing nipple, model MJG mechanical retrievable packer, sliding side door, and 2 7/8” 6.5 #/ft tubing. Set packer at 7400’.
12. MIRU SL, set plug in lower XN nipple, test tubing to 5000 psi for 15 min. RDMO SL.
13. Test backside to 5000 psi for 15 min.14. Install BPV, ND BOPs, NU 5000 psi tree and flowlines, pull BPV, turn well
over to Production15. If required, use lease gas to rock well in, open on 16/64 ck.
Pre Sketch Proposed Sketch
Model MJG packer set at 7400’
Perforations 7500’-7570’ MD. Note, top sand at 7500’, bottom sand at 7610’.
WEG at 7410’
XN at 7405’
SSD at 7390’
2 7/8” 6.5 ppf API EUE N-80 tubing
Sketches and Procedures
Well left with 10 ppg mud in casing
when drilling rig moved off location.
7” 32#/ft casing run to 8000’ with PBTD at 7850’
1. MIRU SL2. Hold safety meeting. Make gauge ring run to PBTD est. 7850’, send results
to Engineering.3. RDMO SL4. If approval to proceed, MIRU completion rig5. Make bit and scraper run to PBTD6. TIH with open ended workstring, displace hole with 9.8 ppg KCL
completion fluid.Note: expected reservoir pressure is 3600 psi at 7500’. 9.8 ppg fluid will provide a 222 psi OB.
7. Test casing to 5000 psi for 15 minutes8. MIRU EL unit, hold explosives safety meeting and conduct JSA. RIH and
9. POOH with guns, check that all shots have fired, if not, inform Engineering10. Monitor hole conditions for 4 hours, report any fluid loss or pressure build
up11. If well stable, TIH with completion string consisting of MS WL reentry
guide, XN landing nipple, model MJG mechanical retrievable packer, sliding side door, and 2 7/8” 6.5 #/ft tubing. Set packer at 7400’.
12. MIRU SL, set plug in lower XN nipple, test tubing to 5000 psi for 15 min. RDMO SL.
13. Test backside to 5000 psi for 15 min.14. Install BPV, ND BOPs, NU 5000 psi tree and flowlines, pull BPV, turn well
over to Production15. If required, use lease gas to rock well in, open on 16/64 ck.
Pre Sketch Proposed Sketch
Model MJG packer set at 7400’
Perforations 7500’-7570’ MD. Note, top sand at 7500’, bottom sand at 7610’.
WEG at 7410’
XN at 7405’
SSD at 7390’
2 7/8” 6.5 ppf API EUE N-80 tubingThis is the proposed sketch. This is what the
completion engineer wants to get to i.e., thefinal state of the well. There is a lot of engineering that goes into this sketch; which isthe overall subject of this module. Consider for now several questions: Why perforate that interval? Why run that packer and that size tubing? Why run tubing at all? Why just perforate, and not frac or gravel
pack?
Design Process for Completion and Workovers Core ═════════════════════════════════════════════════════════════════════════
Just run casing and perforate (a satisfactory option if the reservoir is consolidated and has reasonable permeability)
If the reservoir is unconsolidated, you may need to install some form of sand control
If the reservoir has very low permeability, you may need to fracture the reservoir
1
2
3
In most cases, we will need to select our perforationstrategy as part of this sand face completion – guntype, shots per foot, etc.
See the Sand Control Core and Onshore Unconventional Well Completions Core
modules for more information.
Christmas tree
General requirement to have two barriers in place for any operation
A barrier is used in place for any uncontrolled lossof produced fluids leading to the environment
Barriers change throughout completion/workover operations – this is different from drilling operations where the two barriers (mud and the BOPs) are fairly constant
Barriers
Sub‐surface safety valve
Tubing
Packer
Tubing and Packer
What Engineering Went into this Procedure?
Design Process for Completion and Workovers Core ═════════════════════════════════════════════════════════════════════════
Leverage the skills you’ve learned by discussing the skill module objectives with your supervisor to develop a personalized plan to implement on the job. Some suggestions are provided.
Find and review a completion procedure that has been done in the field.
Find the procedure, the pre-sketch, the proposed sketch, the final sketch and the morning reports.
Review these documents, and discuss your review with a senior completions engineer.
Design Process for Completions and Workovers Core
Design Process for Completion and Workovers Core ═════════════════════════════════════════════════════════════════════════
Marinate chicken for 4 hours in a blend of balsamic vinegar, juice of 2 lemons including the lemon pieces, olive oil, fresh rosemary, garlic, salt, pepper
Prepare basmati rice with sliced mushrooms
Prepare sautéed broccoli, olives, red bell peppers, and green beans, add drizzle of soy sauce and splash of sherry
Prepare salad of lettuce, fresh tomatoes, feta cheese, and salad dressing of choice
Cook chicken in cast iron skillet, with lemon pieces, turning frequently until done, season with garlic, salt, pepper
Place cast iron skillet with chicken in oven on warm with whole fresh basil leaves on top
Lightly wilt spinach in some of the juices from the cast iron skillet
Serve chicken on the wilted spinach, basil on top, with rice, vegetables, and salad
Process Recipe
You may want topause a moment to reviewPAUSE
Cooking Analogy – Introduce the Basis of Design
A lot of thinking
before cooking
Cultural preference?
Taste preference?
Chicken on sale that day?
Had pork the day before?
Health?
Taste?
Equipment?
Design Process for Completion and Workovers Core ═════════════════════════════════════════════════════════════════════════
I'm having some new work colleagues over for dinner, but I'm not sure about their cultural preferences. Chicken is usually safe (but they could be vegetarian!).
No luck frying chicken in a pan because the last few attempts didn’t go so well. I don’t even have a fryer—don’t want to buy one because then I’d fry too much and fried food is not that healthy.
The chicken needs an internal temperature of 250°F. I’ll check it with a thermometer at the end. I will plan for 6 oz. of chicken per person, with two spare portions.
I heard this recipe was good—looks similar to one I’ve done before, but I like the heavy use of basil and lemon. This is an important dinner, so it needs be right.
I wanted beef for dinner, but it was expensive and chicken was on sale. Plus, I had pork last night.
My basil in the garden is ready to pick, so I will include chicken basil and lemon.
I don’t like fried chicken—well, I do but I can’t take the calories, and how do I fry basil?
No recipe required. I’ve done this plenty of times. I just know what to do. Now, where is that bottle of wine? For me, not the recipe…
These above two scenarios would be considered the basis of design for this meal—the “why” behind the “what”. The recipe is not the why, just the what. And again, please note that we have two very different BODs that lead to the same dinner plate.
Design Process for Completion and Workovers Core ═════════════════════════════════════════════════════════════════════════
1. MIRU SL2. Hold safety meeting. Make gauge ring run to PBTD
est. 7850’, send results to Engineering3. RDMO SL4. If approval to proceed, MIRU completion rig5. Make bit and scraper run to PBTD6. TIH with open ended workstring, displace hole with
9.8 ppg KCL completion fluid* Note: expected reservoir pressure is 3600 psi at 7500’. 9.8 ppg fluid will provide a 222 psi OB
7. Test casing to 5000 psi for 15 minutes8. MIRU EL unit, hold explosives safety meeting and
conduct JSA. RIH and perforate 7500–7570’ (reference OH log dated Nov 9, 2016) with 4 5/8” gun loaded 6 spf, 60 deg phasing,32 gm RDX charges
9. POOH with guns, check that all shots have fired, if not, inform Engineering
10.Monitor hole conditions for 4 hours, report any fluid loss or pressure build up
11. If well stable, TIH with completion string consisting ofMS WL reentry guide, XN landing nipple, model MJG mechanical retrievable packer, sliding side door, and 2 7/8” 6.5 #/ft tubing. Set packer at 7400’
12. MIRU SL, set plug in lower XN nipple, test tubing to 5000 psi for 15 min. RDMO SL.
13.Test backside to 5000 psi for 15 min.14. Install BPV, ND BOPs, NU 5000 psi tree and flowlines,
pull BPV, turn well over to Production15. If required, use lease gas to rock well
in, open on 16/64 ck.
Pre Sketch Proposed Sketch
Example BoD for our Example Well
Well left with 10 ppg mud in casing when drilling rig moved off location
2 7/8” 6.5 ppfAPI EUE N-80 tubing
SSD at 7390’ Model MJG packer set
at 7400’ XN at 7405’ Lock mandrel with pressure
gauges hung off Feb 15 ‘17 WEG at 7410’ Perforations 7500’–7570’
MD. Note: top sand at 7500’, bottom sand at 7610’
7” 32#/ft casing run to 8000’ with PBTD at 7850’
You may want to pause a moment to review the information.
PAUSE
Design Process for Completion and Workovers Core ═════════════════════════════════════════════════════════════════════════
The Basis of Design is a critical document to facilitate long term organizational learning. From the well sketch and procedure, it is fairly easy to see WHAT was done, but it is very difficult to know why.
The Basis of Design documents all the assumptions and data that went into that design and provides the context for the design.
Remember: You want to provide context around your decisions to engineers that aren’t yet born—company standards will change, regulations will change, technology will change.
Design Process for Completion and Workovers Core ═════════════════════════════════════════════════════════════════════════
Leverage the skills you’ve learned by discussing the skill module objectives with your supervisor to develop a personalized plan to implement on the job. Some suggestions are provided.
Find and review a Basis of Design statement used in your company for a recent completion.
Discuss your review with a senior completions engineer.
Note, not all companies have these titled documents, if not, talk with a senior completions engineer about how the elements within a typical BoD are incorporated into your company’s work process.
Find and review a Basis of Design statement used in your company for a recent completion.
Discuss your review with a senior completions engineer.
Note, not all companies have these titled documents, if not, talk with a senior completions engineer about how the elements within a typical BoD are incorporated into your company’s work process.
Design Process for Completions and Workovers Core
Basis of Design
Design Process for Completion and Workovers Core ═════════════════════════════════════════════════════════════════════════
Before we begin our mid-module review, let’s review the typical work products that a completion or workover engineer would perform or do in most operating companies. These would include AFEs (or Authority for Expenditures), AARs (After Action Reviews) and perhaps CWOPs (Complete the Well on Paper). AFE is almost always done as part of normal work product. AAR and CWOP are not always done on every well.
Design Process for Completion and Workovers Core ═════════════════════════════════════════════════════════════════════════
As part of the procedure, the completion engineer will almost always prepare the expected cost. That cost, along with the expected hydrocarbon rate from the well, oil or gas, will allow for the economic justification for that work to proceed. As always, there are some exceptions. Plug and abandonments need to be done for regulatory requirements and, of course, any serious loss of barriers usually requires a very quick workover. Even here, however, we’d like to know the cost for planning purposes, even if there is no expected profit from the work. For the majority of completion, workover or intervention work, there is an economic justification to be done, and that requires us to know the cost, or the cost for general planning purposes.
The cost estimate, prepared by the completion engineer, gets formalized and approved by the appropriate level of management. That becomes then, the AFE, the authorization or authority for expenditure.
If it appears that the costs will go over what was expected, it may be required to complete a supplementary AFE (and have it approved by the appropriate level of management).
Engineers usually prepare this estimate based on rig day rate costs, time estimates, and estimates for all the products and services required.
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It is generally a good idea to conduct formal after action reviews; usually on wells where there is a significant difference between the plan and the actual events. Or perhaps we would do this in the first five or ten wells of a new development to capture learnings early on. When we see a large difference between the plan and actual events, this could be for the better or this could be for the worst. We might have had a so called train wreck on the well and wish to delve deeply into the reasons behind that event. Or we may have done a few things differently and saved significant time or cost off the planned well. That’s also a very good situation to review and document the reasons behind the positive outcome. Usually after action reviews are done in an open meeting format with representatives from Operations, Engineering, and other involved parties including service companies present. They will review what happened after the action is finished. This is documented and becomes part of the next well or wells planning cycle.
Once a completion or workover is finished, it may have a formal “After Action Review”.
This review is typically done on wells where there was a large difference between the plan and the actual events, or perhaps in the early stages of a development to capture learnings.
The review is usually done in a meeting format, with representatives from Operations, Engineering, and other involved parties all present to Review what happened After the Action is finished.
These AARs are documented and will become part of the next well’s planning cycle.
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Another planning method occasionally engaged in the completion world would be a CWOP; i.e. Complete the Well on Paper. Please note there is also a DWOP which is a Drilled Well on Paper exercise for the drilling portion of the well. This occurs before the well is completed, ideally with enough lead times such that any changes or ideas that come out of the CWOP can be implemented on location during the actual completion.
The idea is to get all involved parties together, Engineering, Operations, the rig contractor, all the service providers, and carefully go through the planned completion procedures step by step. The assembled team is looking to leverage all the expertise in the room, and ideally identify time savings, potential problems, develop contingencies, etc.
There is also a degree of team building in these events. If done properly, the same people that are in the meeting will be directly involved in the completion activities.
Not all wells will have the CWOP. These are saved for critical wells.
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Leverage the skills you’ve learned by discussing the skill module objectives with your supervisor to develop a personalized plan to implement on the job. Some suggestions are provided.
Find and review an AFE, AAR, and CWOP.
Discuss your review with a senior completions engineer.
Note, not all companies use all three of these products. You should be able to find an AFE, as these are very standard. If you do not find an AAR or CWOP, discuss the reasons why your company does not use them in your work process – who knows, maybe there is an opportunity for improvement!
Find and review an AFE, AAR, and CWOP.
Discuss your review with a senior completions engineer.
Note, not all companies use all three of these products. You should be able to find an AFE, as these are very standard. If you do not find an AAR or CWOP, discuss the reasons why your company does not use them in your work process – who knows, maybe there is an opportunity for improvement!
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Basis of Design
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This is usually represented as a wheel and comes from the work of Deming.
Project Management
Business Management
Safety Management
Quality Management
Linkage to Management Systems
PLAN
Basis of Design,Proposed Sketch, and CWOP matches up with the procedure
DOOperations follows the procedure
CHECK
Daily morning reports are reviewed by the Operations and Engineering team
ACT
Immediate corrections may be made to the well completion based on new data
The AAR, morning reports, and the post sketch all feed into the next PLAN (a revised Basis of Design and Proposed Sketch).
Many companies actively follow a Project Managementapproach to well drilling and completions.
Several major service companies have divisions that offer fully integrated drilling and completion package divisions, “total” packages, and these typically are built around the project management methodology.
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Well Sketches These may be pre-sketches, proposed sketches, or the actual final sketch.
Procedures
The chronologically ordered steps to get from the pre-sketch to the proposed sketch. We have seen that there is a considerable amount of engineering design that goes into the proposed sketch and the associated procedure, the “what”.
Morning Reports The daily reports that the operations team prepares to document their progress on location.
Basis of Design Statements
The background considerations that went into the proposed sketch and the procedure, the “why” behind the “what”.
Authority for Expenditure (AFE)
The estimated cost of a proposed completion of workover program. This is built from an estimate of the time, daily cost (rig), plus all the equipment and services.
After Action Report (AAR)
A team-based report that discusses what happened during a completion or workover operation, usually with the intent to learn from the event and minimize problems and maximize best practices in the next well(s).
Complete the Well on Paper (CWOP)
A team-based activity that attempts to leverage all the expertise available to improve the procedure or operations BEFORE commencement on site.
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2. Control pressure/fluid path, reservoir to downstream choke
Allows for controlled flow from the reservoir to surface and to the primary process facilities
Facilitates controlled re-entry according to site specifics Allows for artificial lift, if needed Allows for monitoring/diagnostic work Allows for “optimal” inflow from the primary target reservoir Designed for rock properties (permeability, consolidation) Designed for expected fluids and pressures over the life of the well,
considering the reservoir and geology Allows for future changes to the primary reservoir (pressure depletion,
increase in secondary phase) Includes provision for accessing secondary, tertiary, etc., targets Designed to handle all stress cases over the life of the well Incorporates input from procurement, finance, logistics, HR, service
companies, R&D Adheres to all internal and external regulations and specifications If injection is planned, designed to facilitate this change in the future
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The primary objective is to generate an economic return for the Company, so that the Company can continue to exist, and invest in new opportunities. Companies may define “economic return” differently, but one very common measure would be the Net Present Value of a project.
Looking at the chart, on the bottom axis is time, there is always some elapsed time between a project identification and first production – this could be anything from time waiting on a rig to time to analyze seismic data and acquire the lease. This time is usually measured in months to years.
After this upfront time has elapsed, we then usually have a period of substantial investment, shown on the graph as negative money, or money we are spending from our accounts. Again, this could be a single well, or it could be a platform, and multiple wells. Either way, one aspect of the petroleum industry is (typically) a large upfront investment is required before we receive back any money in income from the production. We must drill the well before we can put it on production!
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Looking at the graph and recognizing that our objective is to maximize the net present value of the project over the life of the project, we can see there are only four things we can do to impact the cumulative net present value.
1. We can do the project faster. Remember, we are interested in maximizing the net present value, so anything we can do to get the project online fast should result in a greater NPV. This is related to inflation and is often termed “the time value of money”.
2. We can do the project for less cost. Lower cost and the same revenue will clearly yield more net present value.
3. We can achieve a higher production rate; or in the case of our unconventional wells, a higher initial production (IP). The more we make, the more we can sell and the more revenue. We also benefit from the timing effects if we get the higher production and higher revenue earlier in the life of the field, again due to the time value of money.
4. And, we can produce for a longer period – extending production out and therefore recovering more reserves and generating more revenue.
These four levers to NPV do not always work in exactly the same direction. We may pay more for a larger frac job to substantially increase our initial production rate. We may choke back initial production rates to be able to use an existing facility. The engineering team will usually consider many economic scenarios to find the right balance between these four items that results in the maximum NPV for the project.
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Let’s now directly relate this to a well completion with a few examples.
What can we do to speed up the time to a completion?
Good logistics can help here especially in remote areas – having the anticipated equipment in country or at a nearby base can drastically shorten the time to complete the well in certain locations. Good procurement practices to arrange favorable frac dates can help in the unconventional world.
What can we do to lower the cost of a completion?
We can obviously get the best price for our equipment and services, and we can also use the most appropriate equipment. Very often the rig cost is a significant portion of the overall cost, so anything we can do to shorten the time to complete the well will help.
What can we do to increase the production rate?
This question links directly to our inflow and outflow equations, and optimizing both. Minimizing completion damage will increase production and ensuring that we have the right sized tubing can also maximize rate.
What can we do to extend the productive life of the well?
Artificial lift would fit this category, as would any of our efforts to set up more than one zone in the initial completion, with dual completions, or selective completions.
Please keep this in mind as you go through this course. The first objective will be to maximize the net present value of the project, or well completion or workover. For every tool or process we discuss, think about how it relates to this graph. If something does not seem to relate to any part of this graph, then it should directly relate to our second objective.
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HSE includes worker safety on location (injury), worker health (MSDS sheets/food preparation), environmental impacts (waste handling), and control of pressurized hydrocarbon fluids.
The second main objective is safety. Now safety, or the requirement for safety, is present throughout the oil field. Included is worker safety, injuries, worker health, MSDS sheets, materials safety data sheets, and even food preparation is important. Many rig sites around the world have their own catering and food preparation directly impacts worker health.
Also consider environmental impacts. This could be normal waste handling of waste generated on location, such as, used drilling mud, leftover cement, regular trash from the catering operations. But very significantly, we are concerned with the control of pressurized hydrocarbon fluids. When control of these fluids is lost, this is often termed a blowout and this tends to have significant negative press. Loss of control of energized hydrocarbons can then lead to loss of life and significant environmental impact.
These are the two primary considerations we will have on any of our design decisions. Maximize our net present value and minimize, reduce and eliminate any safety issue incidents. Profit and safety underpin most of the design choices.
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To achieve the two objectives, below are aspects one must consider: The geologic setting: Depth, pressure, temperature, permeability, consolidation, grain size, clays, etc.
Reservoir engineering: Including inflow equations, drive mechanism, reserves/expected life, fluid types and composition.
Petrophysics: You need the logs to show us fluid contacts, reservoir layering, and the number of zones.
Current well conditions: Cement quality in areas of interest, casing integrity, casing size, well deviation, equipment or “fish” currently in the well.
Facilities: Including capacity for all fluids, including any sales limitations.
Regulations: Internal and external
Logistics/Location access: Where are you in the world and does this somehow impact decisions? Can the location be accessed year-round with any equipment you may desire?
Procurement: Do you have preferred vendors for certain products or services?
There are MANY items that should be considered in a completion design, some relatively global, many local. Good completion design considers as much as possible including, but not limited to, these items discussed here.
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Permeability is king, even in unconventionals. You must understand permeability to understand the potential inflow, tubing sizes, as well as the need for fracturing if the permeability is too low.
Clay content
Needed for selecting compatible completion fluids and stimulation fluids.
Grain sizes
If gravel packing is required, you must know the formation grain sizes to design the pack.
Depth, Pressure, Temperature
This will be used in determining tubing strength requirements and completion fluid density. The deeper the well, the more the tubing will weigh, and the more load on the top tubing joint. More pressure usually means more rate, and potentially larger tubing. More pressure means more likelihood of burst, so again, tubing design. Temperature will impact elastomer selection.
Consolidation
Right after permeability, you need to know something about the consolidation of the rock. Younger rocks may be unconsolidated, and grains of sand may be produced with the hydrocarbon. This can cause erosion, and the completion may require sand control.
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Below is an oil inflow equation, assuming drainage is a circle. There are other equations for Gas and for different flow geometries (horizontal wells).
Where:
= Rate
= Rate of oil
= Permeability to oil in milidarcies
= Height of the reservoir in feet
= Viscosity
= Formation volume factor
= Average reservoir pressure
= Flowing bottomhole pressure
= Drainage radius
= Wellbore radius
= Skin factor
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You must also be aware of reservoir drive mechanisms while designing a completion. Again, the completion is not something that is installed for the well's capability to produce on day one. The completion should be there to maximize the net present value over the life of the well. You must understand with the help of your reservoir engineering colleagues what the drive mechanism will do over time and how that may affect the completion design. All reservoirs have some drive energy which will enable hydrocarbon to be produced into the wellbore from the reservoir.
Several items need to be considered when reviewing the reservoir drive mechanism:
What will happen to pressure over time?
What will happen to the ratio of gas/oil/water over time? (For an oil well, consider the gas/oil ratio and the water/oil ratio.)
If the natural pressure will decline, are there plans to inject something (usually water, could be gas) to maintain pressure?
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Generally, three main types of drive mechanisms areconsidered active in the Petroleum Industry.
Solution Gas Drive
Gas Cap Drive
Water Drive
• There may be a combination ofmore than one type, and theymay have differentcontributions to the overall driveof the reservoir – weak vs.strong water drive, for example
Depletion or Gas Expansion
Water Drive
For Oil Reservoirs
For Gas Reservoirs
Solution Gas Drive
Solution gas drive
• The gas dissolved in oilcomes out of oil andexpands pushing the oil outof the reservoir
Oil Zone
Liberated Gas
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Fluid Composition In addition to understanding the reservoir drive mechanism, you will have to learn about the fluid composition. This is a large area of study for reservoir engineers. As completion engineers, we need to know if we will be producing oil or gas.
► Gas finds possible leak paths much easier than oil, therefore, there isa bigger concern with gas tight tubing connections, etc.
You need to know if there are any non-hydrocarbon components in the fluids.
► Specifically, there is an interest in components that cause corrosion,or enhanced HSE risks; CO2 and H2S, predominately. These twogases when combined with other fluids will have a corrosive effect onyour metals in the well, and you must select the metals to be able toresist the corrosion from either CO2 or H2S. This is discussed furtherin Completion Design Fundamentals module.
Reserves If tasked with optimizing the NPV of the well over the life of the well, you will need to know the lifespan. This is directly related to the size of the reservoir, the location of well in relation to any fluid contacts, and the drive mechanism. Be aware of any other zones encountered in the well.
► Will this well produce one zone for 5 years?► One zone for 25 years?► Or will it produce 3 different zones (approximately 7 years per zone)
over a total of 21 years?
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Measures natural radiation – Gamma Rays Identifies lithology (defines sand/shale boundaries) Works in open hole and in cased wells; this is one of the few
logs that can work through steel casing to identify formation characteristics
Gamma ray helps us identify the sand packages (with porosity and ideally some perm) from shale (think conventional shale, so virtually no perm)
RESISTIVITY
(Ohm – Meters)
Laterolog/Induction Log (Conductivity) Measures resistance to induced current, formation water contains salt, salty water does not resist the flow of electrical current, so low resistivity indicates water.
Hydrocarbon contains low amounts of salt, so oil does resist the flow of electrical current, so higher resistivity generally indicates the presence of hydrocarbon.
Resistivity helps us determine if the sand contains water (salty water) or hydrocarbon – note the sand might contain both, and then we would have an identified hydrocarbon/water contact.
DENSITY
(DENSITY in Grams/cc) Compensated
Formation Density Log
Measures back – scatter of imposed radiation – Gamma rays Detects Lithology and ⌀
The Density and Neutron logs combined help us differentiate gas from oil. Again, we might have both and, therefore, a gas/oil contact.
NEUTRON
LOG Emit NEUTRONS; detect Neutrons
Tool measures amount of hydrogen in formation; porosity derived
The density and neutron tools combined can differentiate gas from oil in a hydrocarbon interval
ACOUSTIC or
SONIC (Microseconds)
Measures transit time of transmitted sound Measures ⌀ Used to also calculate certain rock properties useful for
fracture design.
The Density, Neutron, and Sonic logs can also give provide a measure of the porosity, this is needed for determining reserves.
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Look at a few simple logs to calibrate your understanding and enable you to digest how this information is used in completion design. By convention, it is assumed that anything more than 50% sand in a conventional reservoir would be considered part of your reservoir pay section. In the log below, the 100% shale line is drawn on the right. On the left is the 100% sand or a 0% shale line, and we interpolate between the two of them, draw a 50% shale line. Anything cleaner than the 50% shale line would be sand and you would use in the calculations for reservoir thickness. You can see in the adjacent image it is marked off in yellow.
Given the four most common logs, below is a brief example of an analysis.
On the left track is the gamma ray log, which shows the sand from shale. As a reminder, the gamma ray responds to natural background radiation in the sand or the shales. Shales have a much higher natural background radiation than sands do. In this log, the scale at the top goes from zero gamma ray units to 200 on the right. Moving from the left to the right gets you more shale. The 50% or greater sand line in the yellow is indicated.
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On the resistivity track, there is hydrocarbon in the top red section, and salty water in the lower deep purple section. We mark off an oil-water contact slightly above 1,820.
On the density and neutron logs example in the middle, the crossover of those two logs is identified on the top. This is an indication of the gas zone, and a gas-oil contact can be marked at approximately 1,810. This one sand package on the left has within it all three fluid phases. There is an oil-water contact, therefore you have gas at the top, oil in the middle and water down below. This would drive the completion strategy as we would generally wish to preserve the reservoir energy of the gas and the water and produce only the oil initially. We would place or target our perforations to just produce the oil from the middle of this sand package.
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You must have a good understanding of the current well conditions to create the Pre-Sketch.
The following are of importance:
The condition of the cement in your area of interest.
Casing integrity:
o Is the casing new and successfully pressure tested? o Is the well old (and undergoing a workover) where there is
concern about corrosion? o Are there perforations to consider?
Casing size/pressure rating:
o If a new well, you should have the right sized/rated casing for the intended completion but not always. In workovers that occur years after the initial completion, the casing will need to be assessed.
Wellbore deviation may have an impact in your completion and needs to be at least considered. Some tools might not go through areas of rapidly changing deviation or out into long segments of high deviation.
What is in the well currently?
o If a workover then there will be equipment from the original completion (or prior workovers) that may need to be removed.
o If a new well, what type of fluid is in the well? Is this good enough for our completion, or will we need to change it out?
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Facilities, in their most basic form, take the production from a well, separate the oil, water, and gas and route these three streams appropriately (further treating, sales, disposal, injection).
The equipment used for this separation and routing is on the surface and is sized for a given throughput. There may be limitations in any one piece of equipment, including disposal constraints or possibly even sales (transportation) constraints.
In some parts of the United States, the recent unconventional shale oil boom placed a significant stress on local infrastructure, and although there were wells that could produce oil, there were no pipelines in place and getting the oil to market was a significant logistical challenge.
In addition, the gas was often flared in those areas, there was no local market for gas. Gas is much harder to transport than oil and there was no market, no ability to get the gas to market, so the gas was flared on location.
In a brand-new development, the facilities are designed to match theexpected output of the planned wells.
Over time there may be more targets, or you may identify ways toproduce more hydrocarbon.
Occasionally, there will be facilities restrictions on one or morephases. Perhaps the reservoir water drive was stronger than plannedand water is being produced more than expected, or maybe, there ismore gas to handle.
Check with the Facilities team to assess if there are any constraintsand remember most constraints are just a matter of money toovercome. Keep in mind, the objective is to maximize NPV not tominimize facilities expenses.
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Internationally, logistics may be a serious consideration for design purposes. If you have started a project internationally, there may be a very long lead time to get certain equipment into the country.
► Explosives for perforating, for instance, often must go through alengthy importation process. Sometimes, the best piece of equipmentto use is one that is already in the country.
In addition to general country set location and logistics, we have to consider access to the location itself, even if the location is logistically close to a main oil field service center.
► We can consider a small platform in the Gulf of Mexico being veryclose to the entire Gulf of Mexico oil infrastructure but if the platformis small enough, we may not be able to get equipment that we wouldlike to onto that platform.
The same applies to remote jungle locations and perhaps even locations in rocky areas of the mountains where it is expensive to clear that mountain into a pad, and therefore, smaller pads are prevalent.
We may also have a weather window for doing work. This may be during the summer, this may be during the winter. It all depends on the location.
Access to location: Is this location easily accessed year-round withvirtually any size/weight equipment?
Do we have a size/weight limitation as on some small offshoreplatforms or remote jungle (helicopter access) locations?
Do we have a weather window for doing work?
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Good procurement serves a real purpose in maximizing NPV over the life of the well. Good procurement is not just about lower direct cost but also the correct introduction of technology, lower total cost, and long-term support.
However, we must recognize that procurement is often a factor in well design. Perhaps through first call or sole source contracts, or through other involvement.
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Regulations come in many forms, but we may broadly categorize these as internal and external.
External regulations are usually from the local governing body, for example, the state regulatory agency, OSHA, perhaps BSEE, or internationally the local government agency.
► You should always know the local regulatory agency and be familiar with how your company intends to remain current and comply with regulations.
Internal regulations are from the Company. These often complement the external regulations or translate external expectations into clear requirements.
► Casing must be adequately pressure tested to test casing to 80% of the burst rating for 15 minutes and record on calibrated chart recorder.
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In some places, this has a significant impact on operations and timing and perhaps the design itself. There are some parts of the world where one cannot work a part of the year during weather periods. In other parts of the world, one may be able to work during inclement weather periods. Perhaps we should plan more time and therefore, more money in our cost estimates.
SECURITY
When we talk about surface controlled sub surface safety valves, we will consider the risk assessment to determine if they are needed. Part of this risk assessment should consider local security concerns.
FISCAL REGIME
Technical operating staff should always know the fiscal regime under which they are operating. In some parts of the world, contracts significantly favor CAPEX over OPEX, and this can have an impact on design. It comes back to maximizing the perceived value of the asset.
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It was stated that conventional well completions are individually designed, one at a time, starting from the log. The discussion so far in this module follows a conventional completion process fairly well. We need to consider the log, geology, fluid contacts; i.e. everything in each well's design.
Recently, unconventional completions are not typically individually designed from the log up. They are geometrically designed. By that we mean we will have perforation clusters 30 feet apart, with stages every 150 feet. We're going to do this from the toe of the well to the heel of the well with no real regard for the logs.
Every well in the area will have the same simulation design. We will frack each well the same, and after we do a certain number of wells; or a certain period of time passes, we may do a review and we might adjust our overall design for the next batch of wells. However, recently most unconventional wells are not individually designed from the logs up with individual frack programs designed for each stage based on that well's rock properties at that depth. This is a slight difference between unconventional and conventional wells in 2017.
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Now we’ll go through a series of steps to summarize what has been covered so far in this module. Consider geologic/reservoir parameters, rock characteristics, fluid characteristics, well conditions and everything else into the basis of design. This basis of design will then lead to your design, the completion program, the completion sketch, the proposed sketch, and the AFE.
You may complete a CWOP event to refine this design if you have sufficient justification for the time and cost. Usually these are done on expensive, critical wells.
Then, proceed to the location and work will get done on site through the operations team. They will report their progress through daily morning reports; which the engineering team will use to monitor and support the operation, and to generate the post or final sketch. You can choose to do an After Action Review to gather all of the learnings from this particular completion and feed those back into the “everything else” category that goes into the basis of design for the next well. This category of “everything else” and many of the concepts presented here will be reviewed next.
These steps will be covered in more detail on the next pages.
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For the geologic and reservoir parameters, there is a concern with the geologic characteristics of this reservoirs size, shape and thickness. These will all lead to a reserve estimate which can be used to estimate the time this well will be on production, and how much fluid this well is expected to produce or handle over its life. There is also a concern with the depth, the temperature, the pressures, and other geologic items such as the trap type. For continuity, some questions you may need to answer include, are there variations of permeability across the field that might drive us to require more wells with smaller tubing? Or is this an extremely well-connected field where a few wells with large tubing would be sufficient? You must have a good understanding of your production profile over time. Generally, you will need to work with the reservoir engineering team and others to develop this profile. This will include the inflow equation, how fluid is brought from the reservoir into the well, and the outflow equation. This will be discussed further in the Completion Design Fundamentals module. Again, we are not looking at this on day one of the well's life, but ideally, some idea of the production profile over the life of the well, including changing fluid ratios. We must understand the reservoir drive mechanism and how this will affect the production profile over time.
Geologic Characteristics Continuity Productivity
Size
Shape
Thickness-Reserves
Depth
Temp
Pressure
Trap type
Perm barriers
Perm variations
Continuity
Inflow equation
Outflow equation
Profile over time
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You need to have an understanding of the reservoir rock. Some questions to ask are, Is this a sandstone or a carbonate? Where are the shale barriers? How is the shale and sedimentary rock distributed, is it In layers or In packages? Are there any scale forming contaminants, perhaps, present in the rock? What type of clay do you have? What do they react with? Is the rock well-cemented or loosely cemented? Unconsolidated with a chance of sand production?
What is the porosity of the rock? The permeability? If this rock can or will produce sand, you may need to consider sand control. Are there moveable fines? Perhaps not the main rock grains themselves, but smaller fines may move without moving the larger grains.
If you are going to install a gravel pack, you must understand the grain size distribution. Is the planned completion or simulation fluid compatible with the rock? If discussing a fracture treatment, you will need to know min and max stresses, their directions, Young's modulus, and perhaps other rock properties.
Lithological / Chemical Description
Sedimentary
o Sandstone o Carbonate
Shale Barriers
Shale/Sedimentary
Distribution
Contaminants
o Scale forming
Clay content
o Clay types o Reactivity
Cementation
Porosity
Permeability
Relative Perm
Consolidation
Moveable fines
Grain size distribution
Wettability
Compatibility with planned completion / stimulation fluids
Min/max stresses and directions
Young’s modulus
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Some questions to answer in order to better understand the fluid present are, do you have oil, gas or water? What is the density, or perhaps gravity? What is the viscosity? What is the formation volume factor? Do you have any bubble or dew points? What are the saturations of these fluids in the zones of interest? Are there any contacts that we wish to stay away from in our perforating design?
On the chemical properties of the fluids, what's the total composition? We can use this to perhaps estimate a tendency to form wax in the wellbore. We are certainly concerned with corrosive agents such as H2S and CO2. Are the fluids in the reservoir rock compatible with their planned completion or stimulation fluids?
Physical Properties Chemical Properties
Oil, Gas, Water
o Density/Gravity o Viscosity o B (formation volume
factor) o Pb (bubble point, dew
point)
Saturations
Contact levels
Total composition
Wax content
Asphaltenes
Corrosive agents
o H2S o CO2
Compatibility with planned completion/stimulation fluids
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The current well conditions should be taken into consideration. If this is the initial completion, the current well conditions should be straight-forward. However, if this is a workover, you may be looking at a well that has been in existence for 40 years. You must understand the casing integrity, the cement in the new zone of interest and the cement quality. Is the ideal casing size available to you? Or is there a need to scale down the completion to fit into an existing wellbore? What are the pressure ratings of the casing? Are there any existing perforations?
Directional surveys will need to be reviewed for high angle sections, and this then considered as part of the overall design. If there is equipment in the well, find out what type of equipment, and how old it is. Take into consideration a piece of equipment that has been in the well for 50 years and if it has to be pulled out because it may cause some operational constraints. Do you cut tubing and leave the rest in the well? Are there any identified fish in the well? And what fluids are currently in the well?
Casing/Cement Deviation Well Status
Cement quality
Casing integrity
Casing size
Casing pressure ratings
Perforations
Directional survey
Doglegs
High angle sections
Type of equipment
Age of equipment
Condition of equipment
Remove or leave
Fish
Fluid
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Finally, there is a catch all category that is broken down roughly into 4 sub areas. The first are technical factors – consider facilities, capacity, export capacity, workover, or re-entry considerations. Can you get on this well easily? Is there anything you wish to monitor? Procurement would fall into this category. Added here is all of the offset data from other wells and any previously done after action reviews. That would all feed into the basis of design.
On regulatory considerations, we must contemplate current HSE Health Safety Environment Standards. How will you dispose of any produced water? How will you handle any gas? Do you flare it, or do you sell all the produced gas? Will you commingle zones? You will see this more in a future module, along with a discussion about the commingling requirements generally in place around the world. Who is the local regulatory agency and how do you contact them? How do you get the right permits for the work that will be done? What are the internal regulations? Is there a certain manual we're supposed to follow, or do we have internal regulations scattered throughout the organization?
Let's consider our local political and economic system, particularly if working internationally. Consider the contract type, taxation, production sharing, royalties, and work commitments? Occasionally, oil companies will have a commitment to drill a certain number of wells in a certain timeframe. This commitment has to be balanced out with logistics, rig availability, sand so forth.
There may be employment requirements for local national staff, or you may have incentives to do certain things faster. Are there any security issues? Where are the local hydrocarbon markets? Also consider items related to the environment or the location such as weather and infrastructure. Will this development cause significant local impact that has to be managed? Is there access to the site year-round or only during certain weather seasons? How big is the location and are there other considerations to take? Lastly, how will we manage the logistics?
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