Petroleum Production: Technical Training Program Phase I

Petroleum Production

Technical Training Program Phase I

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Where are we • • • • • •

Found the reservoir Drilled the Well Logged the Well Ran and Cemented Casing Perforated What’s next ?????

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Objectives • •

• • •

• • •

•

Define the basic concepts and terminology used in reservoir engineering. Determine the expected production rate from a given scenario. Describe the skin effect and explain its affect on production. What is the main driving force behind production optimization? Understand and determine how much oil and gas is in the reservoir. Be able to determine the type of hydrocarbon that is in the reservoir. Be able to explain and define drawdown. Be able to explain how water impacts relative permeability and production Be able to compare well production based on Productivity Index

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What is the goal of the customer?

To maximize petroleum production in a cost-effective manner

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Basic Production Engineering Principles

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How much?

• Reservoir understanding • OOIP/ OGIP

• Type of fluid • Boundaries

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Reservoir Understanding

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Petrophysical properties Porosity • •

Primary: From deposition Secondary: Post deposition

Water saturation Volume ratio of

Water Oil Internal Use Only

pore volume bulk volum e

Petrophysical properties

Permeability: Ability to transmit fluids •

Absolute: Only one fluid

•

Effective: 2 or more fluids present

•

Relative: ratio of Effective to Absolute

Remember Billy Bobs!!!

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Formation Volume Factor

Oil  Gas Volume at Reservoir  Oil  Gas Volume at Surface o Oil in formation contains dissolved gas o Gas comes out when pressure decreases

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Original Oil In Place (OOIP) Data required: – Rock porosity –

Size and extent of reservoir (bulk volume)

–

Fluid saturation

–

Volume factor ( >1)

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Original Oil/ Gas In Place

7758 * A * h * * (1  Sw) OOIP  o 43560 * A * h * * (1  Sw) OGIP  g i Where: A= Area of reservoir (Acre)

Sw: Water saturation (ratio)

h: Height of formation (ft)

o: Volume factor (oil) (reservoir bbl/ stb)

 : Porosity of formation (ratio)

gi: Volume factor (gas) (reservoir cuft/ scf)

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Type of fluid Each hydrocarbon reservoir has a phase diagram, a PVT curve Reservoir types: • Under saturated: Above B.P. • Saturated: Below B.P. (two phases)

• Dry Gas: Above D.P Fluid is gas • Retrograde condensate: Below D.P. Liquid is formed and then re evaporates B.P.: Bubble Point D.P.: Dew Point

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Black Oils • Large, heavy, non-volatile molecules • “Low shrinkage oil”

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Volatile Oils • Fewer heavy molecules • “High shrinkage oil” • Large release of rich gas

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Retrograde Condensate • Initially totally a gas 15%Liquid

• Condensate typically won’t flow

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Wet Gases • PVT below reservoir temperature • Remains gas

Gas while in reservoir but liquid fraction at surface conditions

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Dry Gases • No liquid forms

• Primarily methane

Gas while in reservoir and at surface conditions

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Type of fluid

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Exercise # 1

Temperature

Initial Pressure

Final Pressure

°F

Psi

Psi

(oil/ gas)

(oil/gas)

100 Group I

3700

2600

Oil

Oil

Under saturated

105 Group II

2600

1500

Oil (80%)

Oil (20%)

Saturated

Gas (95%)

Gas (92 %)

Retrograde condensate

Gas

Gas

Dry Gas

175 Group III

2500

300 Group IV

3500

1750 1500

Initial fluid Final fluid Type of reservoir

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Boundary Condition

– Steady-State Performance Constant outer boundary pressure

– Pseudo-Steady State Flow Decreasing outer boundary pressure

– Unsteady State Period before stabilized flow is achieved

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Understanding Production

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Fluid Transfer

B

• Fluid always move from higher to lower pressure conditions

A • Pressure losses result in flow reduction

• An oil/ gas well is a system where pressure losses occur in several places

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Pressure Loss Analysis Pressure losses occur at:

• Reservoir • Perforations • Wellbore • Christmas Tree • Choke • Surface lines

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Production types • Natural

• Artificial

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Production types Electronic Controller Drive Head

Lubricator

Armored Cable

Tubing Anchor

Rod Pump

Catcher w/ Arrival Sensor

Gas-Lift Valve

Pump

Rod Pump

Control Equipment

Plunger Pump

Electric Motor

Submersible Electric Pump Hydraulic Pump

Packer Standing Valve (Optional)

Gas Lift

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Bumper Spring Tubing Stop

Plunger Lift

Sucker Rod

Floater/ Stator

ProgressiveCavity Pump

Flow Trough Porous Media

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Darcy

q  KP – – – –

Pressure (P) Permeability (K) Fluid viscosity (μ) Length of flow (L)

1 q L

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Radial flow Radial Coordinates

kA dp q  dr

Pwf

h

A  2rh

Pe (Reservoir pressure)

re rw

(drainage radius/ outer boundary)

(wellbore radius)

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Steady State condition

– – – –

Assumes rate is constant Specific reservoir production mechanism Constant pressure (pe) at boundary (re) Near wellbore condition critical for well production

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Oil field units

141.2q  re   ln  p e  p wf  kh  rw  Where: – Pe = pressure at boundary- reservoir (psi) – pwf= flowing bottomhole pressure (psi) – q = flow rate (STB/day) –  = formation volume factor (res bbl/STB) –  = viscosity (cp) – k = permeability (md) – h = height (ft) – re = outer boundary radius (ft) – rw = wellbore radius (ft)

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Exercise # 2 • Steady-State Example: – Calculate the production rate if the flowing bottomhole pressure is equal to 4,500 psi. – Given:

Pe= k= h= 

5,561 psi 8.2 md 53 ft 1.1 res bbl/STB

 = 1.7 cp re = 2980 ft rw = 0.328 ft

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Production Optimization

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Draw Down Difference between reservoir pressure (pore pressure) and bottom hole flowing pressure • Drives fluid movement • Controlled by pressure reduction at surface • Prevent undesired conditions Pe = Reservoir pressure (psi) Pwf= Bottom hole flowing pressure (psi)

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Production engineering

• Increase flow rate for a giving driving force

• Minimize draw down for a given rate

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Draw Down

q

Pwf Internal Use Only

Productivity Index (J)

q kh J  Pe  Pwf 141.2(ln( re

rw

)

• Draw down differences

• Meaningful comparison • Gas well (J) = Oil well (J)

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Exercise # 3 • Steady-State Example: – Describe a mechanism to increase the flow rate by 50%. – Given:

pi= k= h= 

5,561 psi 8.2 md 53 ft 1.1 res bbl/STB

 = 1.7 cp re = 2980 ft rw = 0.328 ft



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Exercise # 4 •

The HTC #1 was tested for 8hr at a rate of about 38 STB/D. Wellbore flowing pressure was calculated to be 585 psia, based on acoustic liquid level measurements. After shutting the well in for 24hr, the BHP reached a static value of 1125 psia, also based on acoustic level readings. The rod pump used on this well is considered undersized, and a larger pump can be expected to reduce wellbore flowing pressure to a level near 350psia (just above the bubble-point pressure). Calculate the Following: 1. Productivity index J 2. Oil rate for a wellbore flowing pressure of 350 psi 3. Wellbore flowing pressure required to produce 60STB/D

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Production Limiters

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Water Production • Draw down pressure • Water zones present • Water conning • Water disposal on surface • Effective Permeability

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Water Production • Absolute Permeability (K): One fluid

• Effective Permeability (Kx): 2+ fluids • Relative permeability (Krx): Kx/K

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Sand Production

Negative effects of sand production: •Reduced production rates •Sand bridging in tubing/ casing •Erosion of down hole and surface equipment

•Disposal and removal of sand

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The Near Wellbore Conditions

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Near wellbore rs

Pe

r

h

re Where: –

Well centerline

w

Pe = pressure at boundary- reservoir P= pressure at wellbore k = permeability h = height re = outer boundary radius rw = wellbore radius rs = skin radius

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P ideal

P real

Ks

Kf

rw rs

re

Oil field units

 141.2q  re  ln  S  p e  p wf  kh  rw  Where: – Pe = pressure at boundary- reservoir (psi) – pwf= flowing bottomhole pressure (psi) – q = flow rate (STB/day) –  = formation volume factor (res bbl/STB) –  = viscosity (cp) – k = permeability (md) – h = height (ft) – re = outer boundary radius (ft) – rw = wellbore radius (ft) – S = Skin

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Near wellbore

ps  pwf ,real  pwf ,ideal rs rs q q q s ln  ln 2kh 2k s h rw 2kh rw So skin is…

k  rs s    1 ln  k s  rw Internal Use Only

Exercise 5

Kf rs S  (  1) * ln( ) Ks rw

Kf: Ks: rs: rw:

Formation permeability, md Permeability of skin zone, md Skin radius, ft Wellbore radius, ft

•What would be the skin damage value for a 7” (32#/ft) well that has been damaged 4 ft away from the wellbore resulting in reduction of the original permeability from 100 md to 10 md ? •What if the reduction is from 100 md to 1 md?

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Components of Skin

• Sd: Damage Skin: Reduction of formation permeability • Sc+q: Partial completion: Ratio of perforated height to net height

•Slant: Deviation angle (well exposure) •Sp: Perforation skin: Depends on dimensions, number and phasing • “Pseudo skins”: Phase and rate dependent skin

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Skin Values Kf rs S  (  1) * ln( ) Ks rw • Water Blocks

• Horizontal Wells

• Bacteria

• Acidizing

• Multiphase Flow

+

-

• Emulsions • Clay Swelling • Fines/Clay Migration

• Precipitation

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• Hydraulic fracturing (bypassing)

Production Impact

• Lower Production Rates

• Well Fails to Produce According to Darcy’s

• Lost Production Intervals

• Reduction In Permeability

• Premature Abandonment

• Specific to Near Wellbore Area

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Review •For fluid movement to occur a differential pressure is needed. •The differential pressure for fluid to flow into a wellbore is called drawdown.

•Wells that do not have sufficient drawdown to flow on their own need artificial lift. (gas lift or down hole pumps) •Darcy’s law says that flow rate is proportional to drawdown. •Customers goal is to maximize J in a cost effective manner. • Water and Sand production adversely affects well performance • Skin is an additional steady-state pressure drop near the wellbore. •The presence of several fluids impedes the flow of each fluid

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