well completion design introduction
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Well Completion Design IntroductionTRANSCRIPT
Well Completion Design Introduction
• A well completion starts when the drill bit penetrates the pay zone. Every action during drilling and completion can have significant impact on the final productivity of the well.
• The intent of the completion is as a flow path throughout the life of the well and must be aligned with several needs to achieve maximum efficient hydrocarbon recovery:
– It must connect with the reservoir to achieve maximum inflow from the reservoir – It must connect with the reservoir to achieve maximum inflow from the reservoir to the wellbore.
– If a stimulation is needed during the well life, the completion must make an optimum stimulation practical (both possible and economic).
– It must make outflow of the well economic with the lift systems available and in line with governing restrictions and good engineering practice.
– It must contain sufficient flexibility to allow well management activities, including surveillance and well work, that will maximize hydrocarbon recovery.
• Well Control at every step is the most critical issue.
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How does the reservoir impact
production?
• How big is the “tank”? => Interconnected porosity and saturation of
hydrocarbon. Recoverable vs. in-place reserves?
• What, where, when, why and how does it flow? –
– What will flow first? – low viscosity fluids from high permeability and high
pressure zones.
– Where will it flow? – where are the flow channels (high perm streaks, fractures,
vugs) in the reservoirs. Where are the barriers that prevent flow?vugs) in the reservoirs. Where are the barriers that prevent flow?
– When will it flow? – how much drawdown is required? Is a stimulation (frac)
needed? Is a special completion (horizontal or multilaterals) needed to connect to
the specific high value pay zones?
– Why will it flow? – What supplies the differential pressure in the reservoir? How
can the pressure differential be improved (pressure support)?
– How does it flow? – PVT (pressure, volume, temperature) information, add heat?,
add solvent?, add microbes?, add vibrations?, add ?????
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Reservoir-to-wellbore connection
• Good completions engineering is an extension of
good reservoir engineering! The more you know
about the reservoir, the better your completion
can be.
• Look at the possible connections – which can
process the fluids in the best manner? Each is
right and each is wrong for specific applications.
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What is best configuration to make
the best flowing connection?
• Considerations:– Compartments – barriers, separate pays, thick pays, flanks,
multiple structures, etc., you must contact it to drain it.– Choke points – convergant radial flow creates a choke and
large pressure drops.– Permeability – what is reservoir perm compared to frac
perm? Are perfs & casing a choke point in highest perm formations?perm? Are perfs & casing a choke point in highest perm formations?
– Bed tilt – does the wellbore line up with the horizontal perm? (Vertical perm is often << 10% of horizontal perm).
– Drive mechanism – is coning (gas or water) a problem?– Will the wellbore line up with the frac or will an inflow choke
point be created?– Will the drive mechanism bypass the hydrocarbons? Different
permeabilities in multiple zones or layers must be managed by zone conformance techniques.
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Effect of Well Deviation
• Natural flow is dominated by gas expansion. In a vertical well, hindered settling causes the liquids to rise as the gas bubbles rise as the gas bubbles rise and expand.
• In a deviated well, density segregation makes the process more difficult.
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Outflow in the Completion
• Maximizing flow depends on removing pressure
losses – the highest drawdown usually produces
the most fluids.
• Major and minor losses of pressure include:• Major and minor losses of pressure include:
– Major: flow and lift efficiency and pipeline operating
pressures.
– Minor: perf and pipe friction, choke usage, facilities
pressure drops.Where are the pressure drops?
What are the risks to installation?
What can be done to minimize the
pressure drops.
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Outflow and Lift:
• Wide variation exists in lift method efficiencies:
3840
52
40
50
60
Intermittent GL
Continuous GL
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• However:– Every lift system has limitations
imposed by design,
– Every application imposes requirements on the lift system.
12
18
3840
0
10
20
30
Continuous GL
ESP
Hydraulic Lift
Beam Lift
Limits? Power availability, gas
production, solids production, fluid
viscosity, well deviation, total rates,
temperatures, intermittent flow,
Tubular Design Thoughts
• The wellbore is a series of pressure and fluid containment vessels. It must
function correctly throughout the life of the well and for every operation that
can be expected during the well’s life.
• A well is designed from the inside out and from the bottom to the top. The
size of the tubing or pump required for target production at the highest total
fluid rate sets the casing diameter at the bottom of the well. This bottom
casing size sets the sizes used above it.casing size sets the sizes used above it.
• The materials used in construction must be suitable for operations at the
highest and lowest pressures of all the fluids that will be produced.
• The general approach of concentric or nested tubular construction is to have
the inner string collapse before the outer string busts…..
This
Not
This
You can usually repair a collapsed inner
string easier and with less environmental
impact than a burst in an outer string
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Tubular Construction
• A set of pressure and fluid containment
vessels….. A well may use several full or partial casing strings.
Each sting fits through the one above it. Isolation of these
strings with cement forms annulus areas between the
outside of an inner string and the inside of an outer string.
Pressures creased by lift and heat from flow must be Pressures creased by lift and heat from flow must be
managed to prevent well failures.
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Where are the casing strings set?
• The casing string set points are
dictated by the formation pressures
(high and low), the fluids in those
formations, the need to control
physical or chemical reaction of the
formation (e.g., shale instabilities).
• The drillers work in a “window” of • The drillers work in a “window” of
minimum pressure to control the
highest formation fluid pressure or
rock failure and a maximum pressure
before the weakest formation
fractures.
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Cementing – making the pressure
seal
• Placing a cement slurry of the correct density and volume to create a pressure seal is the final step of the casing process.
• Some factors:
A corrosive
water zone,
unstable
rock or a • Some factors:
– The mud and mud cake must be removed before the cement can form a tight seal between the pipe and the formation.
– The cement slurry must remain pumpable to the end of the job. Fluid loss control, contamination prevention, retarders to handle
rock or a
salt zone
would be
reasons to
bring the
cement
higher.
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Tubing – the flow path
• Tubing is run inside the casing after cementing to
provide a isolated flow path that is better suited
to: the corrosivity of specific fluids; the need to
lift by natural lift or artificial lift; pressure
containment, or other factors. containment, or other factors.
• The size of the tubing depends on:
– Tubing performance at maximum
inflow and minimum economic rates,
– Critical flow rate to lift the fluids,
– Minimization of friction during flow,
– Preventing erosion (upper limit on flow),8/25/2015 12
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The Packer• A packer is a tool used to form an
annular seal between two concentric strings of pipe or between the pipe and the wall of the open hole.
• packer is usually set just above the producing zone to isolate the producing interval from the casing
Latch or threads
Upper slips
Elastomer package
Permanent Packer – holds both directions
producing zone to isolate the producing interval from the casing annulus or from producing zones elsewhere in the wellbore.
• Selection depends on pressures, reliability and need to pull. Specific needs drive slip design, packer bore size and use of a PBR (polish bore receptacle).
Weatherford
Elastomer package
Lower slips
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Subsurface Safety Valve – for
offshore and special
applications• Primary purpose is
shut-in of the well in event of loss of surface well head integrity.
• Types – ball and flapper• Types – ball and flapper
• Control Point
– ScSSV – surface control
– Storm Chokes -subsurface
• Conveyance
– Tubing conveyed – part of the tubing string
Flow Tube
Flapper
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Wellheads and Trees
• Serves as the control point
• Must handles flow, pressure, access,
surveillance and other activities through the life
of the well.of the well.
• Simple to extremely complex.
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Production Chokes
• Chokes:
– Control Flow – achieve liquid
lift
– Maximize use – best use of
gas (lift?)
Maximize use – best use of
gas (lift?)
– Protect equipment –
abrasion and erosion
– Cleanup – best use of
backflow energy
– Control circulation – holds a
back pressure
– Control pressures at surface
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The Surface FacilityFluids are produced as a mixture, sometimes an emulsion with 4 components (gas, water,
oil and solids). It must be separated and treated before it can be sold.
Horizontal Separator.
emulsionwater
oil
dump
valve
dump
valve
clean oil
The liquid section is the active separation layer and the site of chemical
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Well Integrity Management
• Well Integrity is the application of technical,
operational and organizational solutions to
reduce the risk of uncontrolled release of
formation fluids throughout the life cycle of the formation fluids throughout the life cycle of the
well; and the preservation of the formation from
outside influences that would have an adverse
effect on its capacity to produce. (Well Integrity Management
– GOM Dave Porter)
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