Nodal Analysis, Well Problem Analysis, Wax and Sand Control Sanjay K. Dhiraj Dy. SRE, G&R Deptt.
Nodal Analysis, Well Problem
Analysis, Wax and Sand Control
Sanjay K. Dhiraj Dy. SRE, G&R Deptt.
Objectives
Understand the components of Inflow
performance
Understand the components of vertical
lift performance
Understand combining inflow and vertical
lift performance
Wax problem analysis
Sand problem analysis
INJECTION GAS
PRODUCED FLUID
WELL
INFLOW (IPR)
WELL OUTFLOW
RELATIONSHIP
(VLP)
SURFACE PRESSURE
SANDFACE
PRESSURE
BHFP
RESERVOIR
PRESSURE
BOTTOM HOLE PRESSURE AS A FUNCTION OF FLOWRATE
PRODUCTION POTENTIAL AS A FUNCTION OF PRODUCTION RATE
P e
_
P r P wfs P wf
P dr
P ur
P usv
P dsv
P wh
P dsc P sep
D P 1 = P r - P wfs = Loss in Porous Medium
D P 2 = P wfs - P wf = Loss across Completion
D P 3 = P ur - P dr = Loss across Restriction
D P 4 = P usv - P dsv = Loss across Safety Valve
D P 5 = P wh - P dsc = Loss across Surface Choke
D P 6 = P dsc - P sep = Loss in Flowline
D P 7 = P wf - P wh = Total Loss in Tubing
D P 8 = P wh - P sep = Total Loss in Flowline
Possible Pressure Losses in Complete Production System
Bottom
Hole
Restriction
Safety
Valve
Surface
Choke
Separator
Pressure Losses
Inflow Performance Curve
0
500
1000
1500
2000
2500
3000
3500
0 500 1000 1500 2000 2500 3000 3500 4000 4500
Production rate, STB/D
Flo
win
g b
ott
om
ho
le p
ressu
re, p
si
Inflow (Reservoir) Curve
Tubing Curve
0
500
1000
1500
2000
2500
3000
3500
0 500 1000 1500 2000 2500 3000 3500 4000 4500
Production rate, STB/D
Flo
win
g b
ott
om
ho
le p
ressu
re, p
si
Tubing Curve
0
500
1000
1500
2000
2500
3000
3500
0 500 1000 1500 2000 2500 3000 3500 4000 4500
Production rate, STB/D
Flo
win
g b
ott
om
ho
le p
ressu
re, p
si
Inflow (Reservoir) Curve
Tubing Curve
System Graph
INFLOW PERFORMANCE
SEMI (PSEUDO) STEADY STATE INFLOW (using
average reservoir pressure) kh(Pav - Pwf)
qo = -----------------------------------
141.2 oBo.[ln(re/rw) - 3/4]
where: P = pressure (psi)
k = permeability (md)
h = height (ft)
re = drainage radius (ft)
rw = wellbore radius (ft)
O = fluid viscosity (cP)
Bo = formation volume factor (bbls/stb)
INFLOW PERFORMANCE
PRODUCTIVITY INDEX
The relationship between well inflow rate and pressure
drawdown can be expressed in the form of a Productivity
Index, denoted ‘PI’ or ‘J’, where:
q
q = J(Pws - Pwf) or J = ------------------
Pws - Pwf
kh(Pav - Pwf)
qo = -----------------------------------
141.2 oBo.[ln(re/rw) - 3/4]
WELL & RESERVOIR INFLOW PERFORMANCE ( Successful design depends upon prediction of flow rate)
VOGEL Dimensionless reference curve based on the following equation: Q/Qmax = 1 - 0.2(Pwf/Pws) - 0.8(Pwf/Pws)2
where: Q = the liquid production rate, stb/d Qmax = the maximum liquid rate for 100% drawdown Pwf = bottom hole flowing pressure, psi Pws = the reservoir pressure, psi
FLOW REGIMES
FACTORS EFFECTING VLP
VLP is a function of physical properties not inflow
• Tubing ID
• Wall roughness
• Inclination
• Liquid / gas density
• Liquid / gas viscosity
• Liquid / gas velocity
• Well depth / line lengths
• Surface pressure
• Water cut
• GOR
• Liquid surface tension
• Flowrate
PRESSURE LOSS IN WELLBORE
P/Ztotal = g/gccos + fv2/2gcd + v/gc[P/Z]
TOTAL
PRESSURE
DIFFERENCE
GRAVITY
TERM
ACCELERATION
TERM
FRICTION
TERM
P/Z
CORRELATIONS Babson (1934)
Gilbert (1939 / 1952)
Poettmann & Carpenter (1952)
Duns & Ros
Hagedorn & Brown
Orkiszewski
Fancher & Brown
Beggs &Brill
Duckler Flannigan
Gray
Mechanistic
Proprietary
Effect of Tubing Size on Outflow
Inflow
(IPR)
Outflow
Flowrate (stb/d)
Pre
ss
ure
at
No
de
2 3/8”
2 7/8” 4 1/2”
3 1/2”
Produced Fluids Issues
Gas Oil Water
Hydrates Paraffin/Gel
Corrosion
Emulsions
Scale
Asphaltene
Flowability
Solid
Erosion
Paraffins or Waxes “The Cholesterol of the Petroleum Industry”
Costs the industry billions of dollars annually
Wells Productivity
– Lower production – Downtime during wax remedial jobs – Expensive wax chemicals
Flowlines Management
– Extra insulation on flowlines – Dual lines to enable round trip pigging – Downtime during pigging – Cost of chemical program
• Saturated component of a crude oil – crystallizes
upon cooling
• Structure
• Field Definition A low melting point soft solid deposit that forms on cold walls of well
tubing, flowlines and oil transport pipelines
What are Paraffins or Waxes?
CH3(CH2)nCH3
n > 20 Petroleum Wax
0
0.02
0.04
0.06
0.08
0.10
10 20 30 40 50 600
0.02
0.04
0.06
0.08
0.10
10 20 30 40 50 60
Carbon Number (n+2)
Ma
ss
Dis
trib
uti
on
Crude Oil Wax Deposit
Lab and Field Observation Fluid Behavior
Paraffin Deposition in Flowlines
Heat loss to surrounding
Warm
Crude oil
Toil
@w
all
Wax Appearance Temperature
Cooled
Crude oil
Location from oil wellhead
Current Methods of Paraffin Control
Chemical Inhibition
Thermal Insulation
Hot Solvent Treatment
Mechanical Removal
Chemical Inhibitors for Paraffin Control
• Chemical performance is crude
specific
• Need a rigorous laboratory testing
program to qualify a chemical
• Screening of wax inhibitors using
cold fingers or flow loops
Wax inhibitors, hot solvent / dispersants
Coiled tubing access and wire line
Heat retention using Vacuum Insulated Tubulars (VIT)
Heating cable strap onto tubing string
Paraffin Control for Production Wells
Singh et al., SPE Drilling and Completions, 2007
Wellhead
750 ft750 ft750 ft
Warm
Reservoir
Fluid
1 2 3 4 5 6 7 8 9 10 11 12
Time (Months)
1 2 3 4 5 6 7 8 9 10 11 12
Time (Months)
Oil
Ra
te (
BO
PD
)
0
1000
2000
3000
4000
1
Time (Months) 2 3 4 5 6 7 8 9 10 11 12
Mechanical Methods for Wax Remediation
Pigging – Hard pigs, Scraper pigs, By-pass pigs, Multi-diameter
Coiled tubing – limited reach
SPE 77573
Improved pig design to lower the stuck pig risk
Sand Control What is meant by sand production?
Production of solids - type?
– Formation sand grains
– Formation fines
• Clay and Silica
• Compaction/detrital material
How much?
– 1-10 lbs/1000bbls or 1MMSCF
– In heavy oil, amounts could be very large
How much sand is tolerable?
– Depends on well location – offshore/onshore
– Fluid type - gas or oil
– Well type - subsea/platform/onshore
– Facilities for separation/handling/disposal
Causes of Sand Production
Sandstone strength linked to degree of cementation. Cementation increases over time →older sediments are more consolidated.
• Sand production more common in younger and shallower sediments.
Effects of production (pressure reduction and fluid movement) contribute to formation breakdown due to inertial and viscous forces.
• Pressure depletion increases grain to grain forces → potential to exceed compressive strength→ failure.
Causes of Sand Production
Inertial and viscous forces vary depending on the fluid e.g. gas or heavy oil → potential to exceed tensile strength→ failure.
There is a critical flow rate (drawdown) below which sand production can be minimized.
Relative permeability effects change the capillary forces within the grain structure (cohesion).
Impact on cementation - chemical attack reduces strength → increased risk of sand production.
Problems associated with sand
production Erosion - downhole and surface
Plugging ? – Sump and flowlines
– Perforations
– Pore space - fines!
Near wellbore compaction – Slumping of casing
– Subsidence
– Loss of productivity ( increased apparent skin)
Filling of separators – poor efficiency
Removal difficulties
Disposal of contaminated sand
Effects of Sand Production
Establishing Critical
Rate/Drawdown Well is “beaned up” progressively and sand production is
monitored
Concerns?
– Rock is tested to failure - does this weaken the rock - hysteresis?
– Is the failure affected by fluid type/saturation?
– Is QMSF an economic rate?
Prediction
– For a gas well, QMSF depends on (drawdown)0.5
– For an oil well, QMSF depends on : drawdown /strength / fluid saturation
Sand Management options
Production Rate Control Rate control is achieved by gradually beaning up a well and monitoring for
sand production. There are two principal values which characterise the technique: – – Maximum Sand Free Rate (MSFR) – – Maximum Allowable Sand Rate (MASR)
The onset of sand production in a well directly related to increasing production rate → implies there is critical rate below which sand production will not occur. This is the MSFR.
Establishing the MSFR involves well rate manipulation to the point where sand
is noted. This rate is kept constant until equilibrium is reached, at which point the rate is reduced back to a sand free rate.
The MASR is the rate at which sand production can be tolerated through the
production system without affecting its integrity. Economic decision as the rate which corresponds with the MASR may not be commercially viable (also applies to MSFR). Rate control has some advantages; – Generally lower CAPEX (unless major topsides modifications are required) and
flexibility to incorporate workovers if required. – Appropriate for situations where rates must be limited for water or gas ingress.
Sand exclusion options
• Screenless exclusion – Orientated perforating
– Sand consolidation
– Frac packs
• Physical exclusion - bridging
– Standalone Screens • Standard
• Premium
• Expandable
– Gravel packs
Oriented Perforation
Frac Packing
• Tend to use in heterogeneous, fine grained formations
• Optimal perforation design is
central to success of fracturing treatment.
• Perforations aligned with
maximum stress direction optimize impact of initiation and propagation pressures.
• Use of resin coated proppant
(RCP) may further help stabilize formation
Consolidation
• Treat formation in immediate vicinity of wellbore to bond sand grains.
– Formation must be treated through all perforations; Consolidated sand mass must remain permeable to well fluids; Consolidation should remain constant over time
• Two principal types of treatment;
– Epoxy resin (3 stage treatment) – isopropyl alcohol pre-flush, then resin is pumped followed by viscous oil to displace resin from the pore space). Limitations - only 20 ft at a time, temperature maximum of 100ーC, max clay content 20%.
– Furan, phenolic resins & alkoxysilane– have higher temperature range than epoxy but consolidation may experience brittle failure. Difficult chemicals to handle safely.
Screens - Principles
• Sand control using installed screens is designed to exclude all but the finest formation particles from being produced into the wellbore.
• Effective design of screens requires acquisition of core samples for particle size analysis. Seeking to induce particle bridging and dynamic filtration.
THANK YOU