Methods and systems for determining reservoir properties of subterranean formations with pre-existing fractures

• US 20070083331A1
• Filed: 10/07/2005
• Published: 04/12/2007
• Est. Priority Date: 10/07/2005
• Status: Active Grant

• Current Assignee: Halliburton Energy Services Incorporated (Halliburton Company)
• Original Assignee: Halliburton Energy Services Incorporated (Halliburton Company)
• Inventors: Craig, David
• Granted Patent: US 7,389,185 B2
• Time in Patent Office: Days
• US Class Current: 702/13
• CPC Class Codes: E21B 49/008 by injection test; by analysing pressure variations in an injection or production test, e.g. for estimating the skin factor measuring pressure E21B47/06

Abstract

Methods and systems are provided for evaluating subsurface earth oil and gas formations. More particularly, methods and systems are provided for determining reservoir properties such as reservoir transmissibilities and average reservoir pressures of formation layer(s) using quantitative refracture-candidate diagnostic methods. The methods herein may use pressure falloff data from the introduction of an injection fluid at a pressure above the formation fracture pressure to analyze reservoir properties. The model recognizes that a new induced fracture creates additional storage volume in the formation and that a quantitative refracture-candidate diagnostic test in a layer may exhibit variable storage during the pressure falloff, and a change in storage may be observed at hydraulic fracture closure. From the estimated formation properties, the methods may be useful for, among other things, determining whether a pre-existing fracture is damaged and evaluating the effectiveness of a previous fracturing treatment to determine whether a formation requires restimulation.

Claims

1. A method for determining a reservoir transmissibility of at least one layer of a subterranean formation having preexisting fractures having a reservoir fluid comprising the steps of:

(a) isolating the at least one layer of the subterranean formation to be tested;

(b) introducing an injection fluid into the at least one layer of the subterranean formation at an injection pressure exceeding the subterranean formation fracture pressure for an injection period;

(c) shutting in the wellbore for a shut-in period;

(d) measuring pressure falloff data from the subterranean formation during the injection period and during a subsequent shut-in period; and

(e) determining quantitatively the reservoir transmissibility of the at least one layer of the subterranean formation by analyzing the pressure falloff data with a quantitative refracture-candidate diagnostic model.

2. The method of claim 1 wherein step (e) is accomplished by transforming the pressure falloff data to equivalent constant-rate pressures and using type curve analysis to match the equivalent constant-rate pressures to a type curve to determine quantitatively the reservoir transmissibility.

3. The method of claim 1 wherein step (e) is accomplished by:

transforming the pressure falloff data to obtain equivalent constant-rate pressures;

preparing a log-log graph of the equivalent constant-rate pressures versus time; and

determine quantitatively the reservoir transmissibility of the at least one layer of the subterranean formation by analyzing the variable-rate pressure falloff data using type-curve analysis according to the quantitative refracture-candidate diagnostic model.

4. The method of claim 2 wherein the reservoir fluid is compressible;

and wherein the transforming of the pressure falloff data is based on the properties of the compressible reservoir fluid in the reservoir wherein the transforming step comprises;

determining a shut-in time relative to the end of the injection period;

determining an adjusted time; and

determining an adjusted pseudopressure difference.

5. The method of claim 4 wherein the transforming step comprises:

determining the shut-in time relative to the end of the injection;

At=t−

t_ne;

determining the adjusted time;

$t_a=\left(\stackrel{\_}{\mathrm{\mu <br><br>}<br><br>\text{\hspace{1em}<br><br>}<br><br>c_t}\right)<br><br>{\int <br><br>}_0^{\mathrm{\Delta <br><br>}<br><br>\text{\hspace{1em}<br><br>}<br><br>t}<br><br>\frac{d<br><br>\mathrm{\Delta <br><br>}<br><br>\text{\hspace{1em}<br><br>}<br><br>t}{{\left(\mathrm{\mu <br><br>}<br><br>\text{\hspace{1em}<br><br>}<br><br>c_t\right)}_w};<br><br>$

and

determining the adjusted pseudopressure difference;

Δ

p_a(t)=P_aw(t)−

P_ai where

$p_a=\frac{{\stackrel{\_}{\mathrm{\mu <br><br>}}}_g<br><br>\stackrel{\_}{z}}{p}<br><br>{\int <br><br>}_0^p<br><br>\frac{p<br><br>d<br><br>p}{{\mathrm{\mu <br><br>}}_g<br><br>z};<br><br>$

wherein;

t_ne is the time at the end of the injection period;

μ

is the viscosity of the reservoir fluid at average reservoir pressure;

(μ

c_t)_w is the viscosity compressibility product of wellbore fluid at time t;

(μ

c_t)₀ is the viscosity compressibility product of wellbore fluid at time t=t_ne;

p is the pressure;

p is the average reservoir pressure;

p_aw(t) is the adjusted pressure at time t;

p_ai is the adjusted pressure at time t=t_ne;

c_t is the total compressibility;

c_t is the total compressibility at average reservoir pressure; and

z is the real gas deviator factor.

6. The method of claim 5 further comprising the step of preparing a log-log graph of a pressure function versus time:

I(Δ

p_a)=f(t_a),

where

$I<br><br>\left(\mathrm{\Delta <br><br>}<br><br>\text{\hspace{1em}<br><br>}<br><br>p_a\right)={\int <br><br>}_0^a<br><br>\mathrm{\Delta <br><br>}<br><br>\text{\hspace{1em}<br><br>}<br><br>p_a<br><br>d<br><br>t_a.$

7. The method of claim 5 further comprising the step of preparing a log-log graph of a pressure derivative function versus time:

Δ

p_a′

=f(t_a),

where

$\mathrm{\Delta <br><br>}<br><br>\text{\hspace{1em}<br><br>}<br><br>p_a^{\mathrm{\prime <br><br>}}=\frac{d<br><br>\left(\mathrm{\Delta <br><br>}<br><br>\text{\hspace{1em}<br><br>}<br><br>p_a\right)}{d<br><br>\left(\ln <br><br>\text{\hspace{1em}<br><br>}<br><br>t_a\right)}=\mathrm{\Delta <br><br>}<br><br>\text{\hspace{1em}<br><br>}<br><br>p_a<br><br>t_a.$

8. The method of claim 2 wherein the reservoir fluid is slightly compressible;

and wherein the transforming of the pressure falloff data is based on the properties of the slightly compressible reservoir fluid in the reservoir wherein the transforming step comprise;

determining a shut-in time relative to the end of the injection period; and

determining a pressure difference;

wherein;

t_ne is the time at the end of the injection period;

p_w(t) is the pressure at time t; and

p_i is the initial pressure at time t=t_ne.

9. The method of claim 8 wherein the transforming step comprises:

determining the shut-in time relative to the end of the injection;

Δ

t=t−

t_ne; and

determining the pressure difference;

Δ

p(t)=p_w(t)−

p_i;

wherein;

t_ne is the time at the end of the injection period;

p_w(t) is the pressure at time t; and

p_i is the initial pressure at time t=t_ne.

10. The method of claim 8 further comprising the step of plotting a log-log graph of a pressure function versus time:

I(Δ

p)=f(Δ

t).

11. The method of claim 9 where

12. The method of claim 8 further comprising the step of plotting a log-log graph of a pressure derivatives function versus time:

Δ

p′

=f(Δ

t).

13. The method of claim 12 where

14. The method of claim 9 wherein the reservoir transmissibility is determined quantitatively in field units from a before-closure match point as:

15. The method of claim 9 wherein the reservoir transmissibility is determined quantitatively in field units from an after-closure match point as:

16. The method of claim 5 wherein the injection fluid is compressible and contains desirable additives for compatibility with the subterranean formation wherein the reservoir transmissibility is determined quantitatively in field units from a before-closure match point as:

17. The method of claim 5 wherein the injection fluid is compressible and contains desirable additives for compatibility with the subterranean formation wherein the reservoir transmissibility is determined quantitatively in field units from an after-closure match point as:

18. A system for determining a reservoir transmissibility of at least one layer of a subterranean formation by using variable-rate pressure falloff data from the at least one layer of the subterranean formation measured during an injection period and during a subsequent shut-in period, the system comprising:

a plurality of pressure sensors for measuring pressure falloff data; and

a processor operable to transform the pressure falloff data to obtain equivalent constant-rate pressures and to determine quantitatively the reservoir transmissibility of the at least one layer of the subterranean formation by analyzing the variable-rate pressure falloff data using type-curve analysis according to a quantitative refracture-candidate diagnostic model.

19. A computer program, stored on a tangible storage medium, for analyzing at least one downhole property, the program comprising executable instructions that cause a computer to:

determine quantitatively a reservoir transmissibility of the at least one layer of the subterranean formation by analyzing the variable-rate pressure falloff data with a quantitative refracture-candidate diagnostic model.

20. The computer program of claim 19 wherein the determining step is accomplished by transforming the variable-rate pressure falloff data to equivalent constant-rate pressures and using type curve analysis to match the equivalent constant-rate rate pressures to a type curve to determine quantitatively the reservoir transmissibility.

21. The computer program of claim 19 wherein the determining step is accomplished by transforming the variable-rate pressure falloff data to equivalent constant-rate pressures and using after closure analysis to determine quantitatively the reservoir transmissibility.