BUS – Build-up Survey

SPT – Self-Pulse Testing

Conventional single-well testing is based on long-term monitoring of downhole pressure response to the step change in flow rate (usually shut-in or close-in).

The primary hard data deliverables are:
 

• formation pressure 
  
  
• skin-factor S
   
• average transmissibility in drainage area 
  
  
• time to reach the reservoir boundary 

The conditional deliverables from build-up survey would be:

Deliverables	Description	Non-BUS Input Parameters	Key Uncertainties
V_o = \frac{4 \, \sigma \, t_e \, (1-s_{wi})}{c_t} where   is total compressibility: c_t = c_r + (1-s_{wi}) \, c_o + s_{wi} \, c_w and are rock, oil and water compressibility.	Drainable oil reserves	The rock compressibility is defined from core lab study or empirical porosity correlations Fluid compressibility from PVT Initial water saturation from SCAL	Rock compressibility Initial water saturation
A_e = 4 \, \chi \, t_e where  is pressure diffusivity: \chi = \Big< \frac{k}{\mu} \Big> \, \frac{1}{\phi \, c_t} where is reservoir porosity, is fluid mobility: \Big< \frac{k}{\mu} \Big> = k_a \, \bigg[ \frac{k_{rw}}{\mu_w} + \frac{k_{ro}}{\mu_o} \bigg] is absolute permeability to air, are relative permeabilities to water and oil, are water and oil viscosities	Drainage area	Formation porosity Absolute permeability to air from core study Relative permeabilities from SCAL Fluid viscosities from PVT	Absolute permeability to air Relative permeabilities
h = \sigma \, \bigg< \frac{k}{\mu} \bigg>^{-1}	Effective reservoir thickness	Absolute permeability to air from core study Relative permeabilities from SCAL Fluid viscosities from PVT	Absolute permeability to air Relative permeabilities

As one can see, the drainage area and the reservoir thickness are conditioned by core data which may not be representative of the whole drainage area.

The single-well self-pulse test is based on long-term monitoring of downhole pressure response to the periodic rate step change (usually shut-in or close-in).

If flowrate 

The primary hard data deliverables are:

• formation pressure 
  
  
• skin-factor S
   
• near  and far  zone transmissibility 
  
  
• near  and far  zone pressure diffusivity 
  
  
• time to reach the reservoir boundary 

The SPT is correlating pressure variation with pre-designed flowrate variation sequence and tracks:

• pressure response amplitude which depends on formation transmissibility  

and

• time lag between flowrate variation and pressure response which depends on formation diffusivity .

This allows estimating effective formation thickness  directly from field survey without assumptions on core-based permeability (compare with ) and consequently leads to assessing the drainange area , fluid mobility  and absolute permeability  with lesser uncertainties than in BUS: 

h = \frac{\sigma}{\phi \, c_t \, \chi}

A_e = \frac{4 \, \sigma \, t_e}{c_t \, h}

\Big< \frac{k}{\mu} \Big>  = \chi \, \phi \, c_t

k_a =   \frac{\Big< \frac{k}{\mu} \Big>}{\bigg[ \frac{k_{rw}}{\mu_w} + \frac{k_{ro}}{\mu_o} \bigg]}

The absoluite permeability from SPT  is usually stacked up against core-based permeability  to validate the core samples and assess the effects of macroscopic features which are overlooked at core-plug size level.

Running SPT in two different cycling frequences allows assessing the near and far resevroir zones spearately.

The usual SPT workflow includes several cycling tests with different frequencies, the lower the frequency the longer the scanning range.

This captures variation of permeability and thickness when moving away from well location.

Together with deconvolution, the SPT is reproducing conventional PTA information and providing additional data on pressure diuffusivity.

This maybe used as estimation of permeability and thickness separately and their variation away from well location.