From the Reservoir Limit to Pipeline Flow: How Hydrocarbon Reserves are Produced
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Rock Occurance and Production
Estimate of Rock Occurance and Hydrocarbon Production
0
10
20
30
40
50
60
shale sandstone carbonates
Occurance
Production
Although carbonates are a smaller volume of rock present, they dominate oil production totals (Mid East fields). Why?
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What routes are open to flow?
Individual formations and flow channels within each formation may vary widely in their ability to allow flow of fluids across the reservoir.
Permeability variances between horizontal and vertical are usually very large.
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What is the accuracy of the Information?
Where are the fractures and large pores in the rock?
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Source – Karamat Ali, BP Pakistan
This type of illustration helps to understand reservoir complexity,
compartments, potential pays and water sources. Permeabilities in
these pays are reported at 1 to 9 Darcies.
A cross section of a reservoir
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Segments
• Rock properties and reservoir character, quality, • Reservoir fluid qualities – how they change during movement and over time with
depletion. • Reservoir flow paths and compartments impact on fluid flow • The effects of pressure drop and back pressure on fluid flow in the reservoir • Well Placement and Impact of Wellbore-to-Reservoir contact • Fluid behavior in approach and entry to the wellbore • Lift type and optimization of flow from bottom hole through the tubing • Operations effect on the flow rate –
– Choke settings – Restrictions – Separator operations – Pipeline – Start-ups, operations, shut-downs, stabilizing actions
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Pore Size vs. Permeability
y = 1.3661x2.4865
R2 = 0.982
0
50
100
150
200
250
300
350
0 1 2 3 4 5 6 7 8 9 10
mean hydraulic radius (mm)
perm
eab
ilit
y (
mD
)
SDA-01 Balakhany X (SP2) Hg permeability mDSDA-01 Fasila B (SP3) Hg permeability mDSDA-02 Balakhany VIIIC Hg permeability mDSDA-02 Fasila D (SP4) Hg permeability mDK mDPower (K mD)
Large connected pores and natural
fractures dominate the permeability
of a formation.
Are the flow channels
generally known for a
reservoir?
How can they be found?
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Reservoir Fluids – What a PE needs to understand.
• What phases are present?
• Where are they?
• Do the fluid compositions or quantities change? How?
• How do fluids and fluid changes affect permeability?
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PVT Properties (Pressure Volume Temperature)
• Oil Formation Volume Factor – how many reservoir barrels it takes to equal a stock tank barrel after the oil volume shrinks during production due to loss of associated gas.
• Bubble Point Pressure – the pressure at which free gas is seen in a reservoir with no gas cap.
• GOR – gas to oil ratio of produced oil. • API Gravity (density): APIo = [(141.5/SG)-131.5] • Dynamic Viscosity – the viscosity at reservoir
conditions (temperare and associated gas decrease viscosity making the viscosity in the reservoir lower than the viscosity at surface).
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What happens to the oil viscosity during production? Why?
Reservoir Fluid Viscosity as a Function
of Pressure at 60F
0
2
4
6
8
10
0 2000 4000 6000 8000 10000
Pressure (psia)
Oil V
isc
os
ity
(c
P)
?
?
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Oil Types
• Paraffin Base – Straight chain hydrocarbons. Natural gas
condensates, waxes, lube oils.
• Naphthene Base Oils – Ring or cyclic structure, but single bonds.
– Usual API gravities below 25o API. Dominates the longer chain, heavier weight oils.
• Olefinic Series – double bonds in a straight carbon chain.
• Aromatic Series – double bonds in a ring
Saturated Hydrocarbons
Unsaturated Hydrocarbons
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Oil Types
Aromatic – or cyclic structure carbon chain
Paraffin – or linear carbon chain
Asphaltene (Naphthene) – normally cyclic groups with Nitrogen and Sulfur components (Heavy)
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Hydrocarbon Liquids
• Crude Oils
• Condensates (API 40 and above)
• NGL – natural gas liquids
• LPG – Liquified Petroleum Gas
• LNG – Liquified Natural Gas
Range of compositions from C2 to C6+
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Reservoir Brines
• A vast array of water based fluids from fresh water with very low resistivity to super saturated salt water.
• Tracking the composition of waters and the changes with time can be beneficial to determine the source of water production and leaks.
• Tracking the composition of flow back after a workover or a stimulation that uses an injected brine can signal when the job has cleaned up.
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Water Analysis Over Time
Date NaCl Cl Na Ca Mg pH HCO3 Ba SO4 Fe Sr TDS
12/23/04 112,000 67,961 4,400 680 6.80 230 110 45
01/13/05 104,000 63,107 34,000 3,300 600 8.50 230 100 61 1.3 130
02/11/05 101,000 61,286 32,000 3,000 560 7.46 450 99 20 1.3 130
03/24/05 97,000 58,859 31,000 2,800 550 7.84 166 90 37 0 120 102,000
04/28/05 60,400 31,700 2,680 650 7.90 195 94 10 5.8 127 96,400
05/19/05 59,320 28,100 2,164 612 7.85 225 82 7 1 117 91,140
07/21/05 68,075 36,210 3,441 759 7.68 137 109 4 1 147 109,700
08/11/05 68,075 32,440 2,800 766 7.84 220 99 11 1 132 105,000
11/10/05 58,065 29,000 2,400 470 7.97 176 81 15 1 110 90,508
11/17/05 58,064 29,000 2,400 480 6.35 219 85 0 14 120 90,574
12/29/05 58,064 29,000 2,300 490 7.39 195 75 0 2.3 110 90,440
01/05/06 60,066 32,000 2,600 510 7.87 214 89 0 1 120 95,832
01/19/06 61,067 2,700 520 7.41 195 93 1 0 130 95,909
Deep Water GOM
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Brine Reactivity Factors
1. Ion type (usually cations) in fluids moving through the matrix pores (some impact on fluids in fractures but to a lesser extent)
2. Size of the cations
3. Charge on the cation
4. Effective salt concentration – higher salt concentrations are usually more effective in controlling mineral concentrations. Due to cation exchange, salt concentration is lost from the brine with rock contact.
5. pH – low pH fluids have generally less effect on clays than high pH fluids.
6. Clay location – detridal clays (in the matrix body) are usually less reactive than authogenic (in the pore throat forms).
7. Clay type – Smectite typically has a high reactivity while kaolinite and chlorite usually have low reactivities.
8. Clay form – some clays like illite may have forms like the “hairy or spider web” deposits that can be more reactive due to higher surface areas.
9. Coatings on clays such as heavy oil fractions can prevent many reactions unless removed by soaps or solvents.
10. Time in contact.
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Reactivity of Clays
Mineral Typical Area (M2/g) Cation Exchange Capacity Range (Meq/100 g)
Sand (up to 60 microns) 0.000015 0.6
Kaolinite 22 3 - 15
Chlorite 60 10 - 40
Illite 113 10 - 40
Smectite 82 80 - 150
Size ranges for clays depend on deposit configuration. CEC’s affected by coatings and configurations.
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Load Water Recovery
• Range – 5% to 60%+ : the amount of load fluid recovery depends on the formation properties, the fluids properties, the pressure and the time span between pumping and flow back.
• Assists – some surfactants (not all), alcohol, nitrogen gas.
• Detriments – high vertical permeability, high interfacial & surface tension, long shut-in times, low energy, small pore throats….
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Scale Deposition Causes
• Change in flow conditions make the scale minerals super-saturated and an upset causes precipitation – Temperature change – Pressure change – Outgassing of CO2
– Change in pH – Evaporation of water
• Mixing incompatible waters • Contact with existing scale – scale crystal growth
from ions in the water.
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Rock Structure
• Lithology or mineralogy – describes the solid or matrix portion of the rock, generally the primary mineralogy, e.g., sandstone, limestone, etc.
• Mineralogy analysis often describes the chemical composition of the components of the rock: sand (SiO2), limestone (CaCO3), dolomite (CaMgCO3), anhydrite (CaSO4), clays, etc.
• SEM (Scanning Electron Microscope) analysis shows the shape and form of the minerals.
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Evaluation of Damage and Barriers • Production Logs
– Fluid type and entry or exit at specific intervals,
– Mechanical condition of parts of the well or equipment,
– Fluid movement (and holdup) along the wellbore.
• Production History – Rates and types of fluids, decline %, water increase, etc.
– Sudden changes, flood arrivals, workover tracking.
• Deliverability Tests – Isochronal, flow-after-flow, four point tests – describe the flow from the
formation.
• Buildup & Draw-down Tests – Pressure Transient Analysis (PTA) – Investigates damage extent and depth (?), drainage radius, boundaries, etc.
Requires some critical assumptions.
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Complexity in the Reservoir
Simple Reservoir ? Only in a text
book. How can this reservoir be produced?
What type of completions and what
flexibility are needed to effectively
deplete the reserves.
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XX Reservoir sanction case geologic model
thin eroded formation
• sheet sandstones • internally homogenous • laterally/vertically connected
• post depo erosion
Eroded
sheet sand
sheet sand
sheet sand
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Pay Quality
1 2 4 5 3 6 7 8 9 10 11 12 13
Attribute Range Average
Gross h (TVT feet) 3-82’ 47’
Net Pay (TVT feet) 3-77’ 43’
Net-to-Gross .88-.99 .91
Porosity .25-.31 .29
Sw .10-.30 .18
The XX is a clean and very fine grain bedded to amalgamated sand. Where present, thin shale occurs as interbeds capping
turbidite bed complexes. XX architecture ranges from channelforms and parallel lobes to shingled complexes. Erosion has
removed much of the XX on the ramp causing moderate to significant baffling which limits the effectiveness of the waterflood.
100’
Terrace Ramp
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Inflow – What is the flowpath from near wellbore into the reservoir
Convergent Flow – less and less pore space as fluids near the wellbore – higher friction, higher turbulence.
Even with a fracture, flow towards a single point becomes restrictive as the inflow point is neared.
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Permeability
• Permeability, k, is the ability of the rock to transmit fluids.
• Permeability is controlled by the size of the connecting passages between the pores.
• Secondary porosity, particularly natural fractures and solution vugs dominate permeability – often are 100x the matrix permeability.
• Permeability is NOT a constant – it changes with stress, fluid saturation, produced fluid deposition, stimulations, damage from fluids, etc.
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Relative Permeability Note that the permeability to the starting fluid decreases with invasion of a second
phase, and that permeability to the invading phase gradually increases with
saturation of that phase.
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Permeability Measurements
• Absolute Permeability – the ability of a rock to transmit a single fluid when it is saturated with that fluid.
• Effective Permeability – the ability of the rock to transmit one fluid in the presence of another when the two fluids are immiscible.
• Relative permeability – the ratio between effective permeability to a specific fluid at partial saturation and the absolute permeability.
Source – AAPG Basic Well Log Analysis, Asquith. G., Krygowski, S.
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What is the pressure drop in the Perforation Tunnel
Flow rate in bbls per perf per day
Pressu
re dro
p th
rou
gh th
e perf, p
si
The perforations open a very small area in the casing.
If that area is filled with sand, the pressure drop increases significantly.
SPE
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4600 psi or 313 bar
1000 psi or 68 bar 15 psi
10 psi 25 psi
100 psi
Column Densities:
Gas = 1.9 lb/gal = 0.1 psi/ft = 1900 psi in a 10,000 ft well
Dead oil = 7 lb/gal = 0.364 psi/ft = 3640 psi in a 10,000 ft well
Fresh water = 8.33 lb/gal = 0.433 psi/ft = 4330 psi in a 10,000 ft well
Salt water = 10 lb/gal = 0.52 psi/ft = 5200 psi in a 10,000 ft well
Gas cut flowing oil = 5 lb/gal = 0.26 psi/ft = 2600 psi in a 10,000 ft well
10,000 ft or 3050 m
Press.
Drop
Differential pressure, DP, is actually a pressure balance
4600 psi reservoir pressure
-2600 psi flowing gradient for oil
- 150 psi press drop
- 100 psi through the choke
- 25 psi through the flow line
- 10 psi through the separator
- 15 psi through downstream flow line
-1000 psi sales line entry pressure
----------------------
DP = 700 psi drawdown pressure
Where does the pressure drop or
DP come from?
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Liquid Height Over The Pump – Does it matter?
More fluid height over the pump?
Holds more back pressure.
Restricts the inflow?
May keep gas collapsed!
Less fluid over the pump?
Lower BHFP.
At higher gas content, pump may become gas locked.
Too little fluid increases the potential for pump-off.
The ideal fluid height over the pump depends on fluid and wellbore characteristics.
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Completions - Tubing Performance
TUBING PERFORMANCE RELATIONSHIP
unstable region,well may not flowunder theseconditions.
increasing GOR helps at lowrates (like a natural gas lift).Too much gas hinders(friction).
increasing water cuts meanmore pressure is requiredto flow at same rate.
initial tubing performance curve(0% w/c, initial GOR).
increasing frictionincreasinghydrostatic pressure
Liquid Flowrate
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How Wells Produce - Production Rate and Tubing Sizing
• The pressure drops are plotted against flowrate to give
– inflow performance relationship or IPR
– the tubing performance curve or lift curve
Inflow Performance Relationship (IPR) and tubing Performance Curves
The lift curve = 'required pressure'
(For a particular sized tubing)
The IPR = 'Available pressure'
Pw
Pr
Flowrate
Pump pressure (If a higher rate is required)
31/2" 41/2" 51/2"
drawdown
Barrels of Oil per Day
Bottom holeflowingpressurr
If bottom hole flowing
pressure is the same as
the reservoir pressure
the well will not flow
As the bottom hole pressure is
reduced the well begins to
flow - pushed by the reservoir
pressure. The greater the
drawdown the greater the flow.
Tubing Performance Curves: Calculated by computer or taken
from tables, to predict the pressure loss up the tubing. Depends
upon rate , type of fluid (oil vs gas), gas-oil-ratio, water content
etc. for different tubing sizes.
Natural flowrate: in this
particular case the well
will flow naturally at this
rate with this tubing in
the hole.
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Expansion of gas occurs as the gas rises from the bottom of
the well. The expanding gas can entrain and carry liquid
with it if the flow rate reaches critical velocity (the velocity
necessary to lift liquid).
5,000 ft
2150 psi
2500 ft
1075 psi Remember – the volume of the gas
bubble (and indirectly the velocity of the
upward flowing fluid) is controlled by the
pressure around it. This pressure is
provided by the formation pore pressure
and controlled by the choke and other
back pressure resistances.
Gas breaks out and expands as it flows up the wellbore
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Flow pattern changes with gas expansion. One or more flow patterns may be present in
different parts of the well. Flow patterns may explain differences in lift, corrosion and
unloading.
Mist Flow – external phase is gas with a
small amount of liquid
Channel or annular flow
Slug or churn flow
Piston flow
Bubble flow
Single phase liquid flow
Depth
and
Pressure
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Increasing Gas Injection or GLR
FBHP
– As gas is added, the FBHP decreases due to gas cut liquid. When too
much gas is added, the friction from the flowing volume increases.
Increasing
friction
decreasing
flowing fluid
gradient
Effect of increasing GLR on Flowing Bottom Hole Pressure (FBHP)
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Variable Chokes - good for
bringing wells on gradually and
optimizing natural gas lift flow in
some cases.
Prone to washouts from high
velocity, particles, droplets.
Solutions - hardened chokes
(carbide components), chokes in
series, dual chokes on the well
head.
Chokes
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surface 14.7 psi (1 bar)
5000 ft 2150 psi (146 bar)
(1524m)
10000 ft 4300 psi (292 bar)
(3049m)
292 cm3
2 cm3
1 cm3
What will the expansion of the bubbles produce at surface?
Energy and friction. 11/10/2011 www.GEKEngineering.com 38
Size of a Bubble Rising in a Liquid Column
Inlet
Impingement
Plate
Liquid Oil
Water, to disposal well
Mist Eliminator
Gas 3-Phase Horizontal Separator
Large interface to promote gas separation
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Conclusions
• The Flow System – from reservoir to pipeline
– Every pressure drop lowers production
– Pressure drops:
• Converging flow
• Damaged permeability or natural fractures
• Low flow capacity fractures
• Perforations that are partly plugged
• Liquid in the wellbore
• Choke backpressures
• Friction in tubulars
• Facility backpressures 11/10/2011 www.GEKEngineering.com 40
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