Сomparative analysis between:

• the reservoir fluid deliverability (the ability of reservoir to produce or take-in the fluid) which is called Inflow Performance Relation (IPR)

and

• wellbore fluid deliverability (the ability of well  to lift up or lift down the fluid) and which is called Lift Curves (LC) (also called  Vertical Lift Performance (VLP) or Tubing Performance Relation (TPR) )

Definition

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It is based on correlation between surface flowrate and bottomhole pressure flowrate 

Application

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• Setting up the optimal production targets
  Generating WFP – Well Flow Performance tables as input for 3D simulations 
  

Technology

• the required production or injection regime for each well upon the current formation pressure, reservoir saturation and production target specified by FDP 
  
  
• Generating Lift Curves (LC) tables as input for Reservoir Flow Modelling (RFM)
  
  

Technology

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AnchorStabilisedStabilisedMost reservoir engineers exploit material balance thinking which is based on long-term well-by-well flow rates surface flowrate targets  (where whether producers or injectors).

In practice, the flow rate flowrate targets are closely related to bottomhole pressure and associated limitations and require a specialised analysis to set up the optimal lifting (completion, pump, chocke) parameters. 

This is primary domain of WFP analysis.

WFP is performed on stabilised wellbore and reservoir flow and does not cover transient behavior behaviour which is one of the primary subjects of Well Testing domain.

The wellbore flow is called stabilised if the delta pressure across wellbore is not changing over time.

The formation flow is called stabilised if the well productivity index is not changing over time.

It's important to remember the difference between constant rate formation flow and stabilised formation flow.

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On the other hand, the constant rate formation flow may not represent a stabilised formation flow as the bottom-hole pressure and productivity index maybe still in transition after the last rate change.

The WFP methods are not applicable if the well flow is not stabilised even if the flow rate is maintained constant. 

There are two special reservoir flow regimes which are both stabilised and maintain constant flow rate:  steady state regime (SS) and pseudo-steady state regime (PSS).

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The pseudo-steady state (PSS) regime is reached when the flow is stabilised  with no pressure support at the external boundary.

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As for formation and bottom-hole pressure in PSS they will be synchronously varying while in SS they will be staying constant.

The table below is summarizing the major differences between SS and PSS regimes.

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It's again important to avoid confusion between the termines stationary conditions (which mean that refered properties are not chaning in time) and stabilised flow conditions which may admit pressure and rate vraition.

In practice, the productivity index is usually not known at all times as there is no routine procedure to assess it.

It is usually accepted that a given formation takes the same time to stabilise the flow after any change in well flow conditions and the stabilisation time is assessed based on the well tests analysis.

Although, this is not strictly true and the flow stabilisation time depends on well-formation contact and reservoir property variation around a given well.

This is also compromised in multi-layer formations with cross-layer communication. 

The conventional WFP – Well Performance Analysis is perfomed as the 

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• Vertical Lift Performance also called Outflow Performance Relation or  Tubing Performance Relation

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IPR –

• Inflow Performance Relation

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• (

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  which may be non-linear. 

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• IPR

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J_s(q_{\rm liq}) = \frac{q_{\rm liq}}{p_R-p_{wf}}

for oil producer with surface liquid production

• ) – responsible for reservoir deliverability (see below)
  
  

• Lift Curves (LC) – responsible for well deliverability  (see below )

Anchor
JP JP

The intersection of IPR and Lift Curves represent the Stabilised wellbore flow (see Fig. 1)

Given a tubing head pressure 

Workflow

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1. Check the current production rate against the production target from FDP
   
   
2. If the diffference is big enough to justify the cost of production optimization (see point 8 below) then proceed to the step 3 below
   
   
3. Assess formation pressure based on well tests
   
   
4. Simulate IPR / LC based on the current WOR/GOR
   
   
5. Calculate the stabilized flow bottom-hole pressure
   
   
6. Gather the current bottom-hole pressure

   LaTeX Math Inline
   body p_{wf}

   
   
   
7. Check up the calculation aganst the actual 

   LaTeX Math Inline
   body p_{wf}

   
   
   
8. Recommend the production optimisation activities to adjust bottom-hole pressure 

   LaTeX Math Inline
   body p_{wf}

   :
   
   
   • adjusting the choke at surface
     
     
   • adjusting the pump settings from surface 
     
     
   • changing the pump depth
     
     
   • changing the tubing size
     
     
   • changing the pump
     
     

The above workflow is very simplistic and assumes single-layer formation with no cross-flow complications.

In practise, the WFP analysis is often very tentative and production technologists spend some time experimenting with well regimes on well-by-well basis. 

See Also

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Petroleum Industry / Upstream / Production / Subsurface Production / Well & Reservoir Management

Subsurface E&P Disciplines / Production Technology 

[ WFP – Water Injector ]

[ Inflow Performance Relation (IPR) ] [ Lift Curves (LC) ]

Anchor
WFP WFP

References

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Joe Dunn Clegg, Petroleum Engineering Handbook, Vol. IV – Production Operations Engineering, SPE, 2007

Michael Golan, Curtis H. Whitson, Well Performance, Tapir Edition, 1996

William Lyons, Working Guide to Petroleum and Natural Gas production Engineering, Elsevier Inc., First Edition, 2010

Shlumberge, Well Performance Manual

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J_s(q_g) = \frac{q_g}{p_R-p_{wf}}

for gas producer

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J_s(q_g) = \frac{q_g}{p_{wf}-p_R}

for gas injector

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J_s(q_w) = \frac{q_w}{p_R-p_{wf}}

for water injector

where

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Based on these notions the general WFP – Well Flow Performance can be wirtten in universal form:

p_{wf} = p_R - \frac{q}{J_s}

providing that  

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For a single layer formation with low-compressibility fluid (like water) the PI does not depend on drwadown (or flowrate) 

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This is a typical WFP – Well Flow Performance plot for water supply wells, water injectors and oil producers above bubble point.

The PI can be estimated using the Darcy equation:

J_s = \frac{2 \pi \sigma}{ \ln \frac{r_e}{r_w} + \epsilon+ S}

where 

For gas wells, condensate producers, light-oil producers, and oil producers below bubble point 

It can be interpreted as deterioration of near-reservoir zone permeability with fluid velocity is growing.

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Fig.2. WFP – Well Flow Performance for compressible fluid production (gas, light oil, saturated oil)

In general case of saturated oil, the PI 

But when field-average formation pressure is above bubble-point 

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Despite of terminological similarity there is a big difference in the way WFP  and Well Testing deal with formation pressure and flowrates which results in a difference in productivity index definition and corresponding analysis.

This difference is summarized in the table below:

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field-average pressure within the drainage area

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average pressure value at boudary of the drainage area

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VLP – Vertical Lift Performance

VLP – Vertical Lift Performance  also called Outflow Performance Relation or  Tubing Performance Relation represents the relation between the bottom-hole pressure 

p_{wf} = p_{wf}(q)

  which may be non-linear. 

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Sample Case 1 –  Oil Producer Analysis

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Sample Case 2 – Water Injector Analysis

Sample Case 3 – Gas Producer Analysis

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