Well Design - PE 413 Chapter 1: Fracture Pressure

1. Well Design - PE 413 Chapter 1: Fracture Pressure

2. Fracture Formation Pressure Definition and Mechanism Fracture pressure is the pressure in the wellbore at which a formation will crack The stress within a rock can be resolved into three principal stresses. A formation will fracture when the pressure in the borehole exceeds the least of the stresses within the rock structure. Normally, these fractures will propagate in a direction perpendicular to the least principal stress.

3. Fracture Formation Pressure Definition and Mechanism At sufficient depths (usually below 1000 m or 3000 ft) the minimum principal stress is horizontal; therefore, the fracture faces will be vertical. For shallow formations, where the minimum principal stress is vertical, horizontal (pancake) fractures will be created.

4. Fracture Formation Pressure Definition and Mechanism

5. Fracture Formation Pressure The Leak-off Test – Limit Test - Formation Breakdown Test The pressure at which formations will fracture when exposed to borehole pressure is determined by conducting one of the following tests: • Leak-off test • Limit Test • Formation Breakdown Test

6. Fracture Formation Pressure The Leak-off Test – Limit Test - Formation Breakdown Test The procedure used to conduct these tests is basically the same in all cases. The test is conducted immediately after a casing has been set and cemented. The only difference between the tests is the point at which the test is stopped. The procedure is as follows: 1. Run and cement the casing string 2. Run in the drillstring and drillbit for the next hole section and drill out of the casing shoe 3. Drill 5 - 10 ft of new formation below the casing shoe 4. Pull the drillbit back into the casing shoe (to avoid the possibility of becoming stuck in the openhole)

7. Fracture Formation Pressure The Leak-off Test – Limit Test - Formation Breakdown Test 5. Close the BOPs (generally the pipe ram) at surface 6. Apply pressure to the well by pumping a small amount of mud (generally 1/2 bbl) into the well at surface. Stop pumping and record the pressure in the well. Pump a second, equal amount of mud into the well and record the pressure at surface. Continue this operation, stopping after each increment in volume and recording the corresponding pressure at surface. Plot the volume of mud pumped and the corresponding pressure at each increment in volume.

8. Fracture Formation Pressure The Leak-off Test – Limit Test - Formation Breakdown Test 7. When the test is complete, bleed off the pressure at surface, open the BOP rams and drill ahead It is assumed in these tests that the weakest part of the wellbore is the formations which are exposed just below the casing shoe. It can be seen in the next slide that when these tests are conducted, the pressure at surface, and throughout the wellbore, initially increases linearly with respect to pressure. At some pressure the exposed formations start to fracture and the pressure no longer increases linearly for each increment in the volume of mud pumped into the well. If the test is conducted until the formations fracture completely, the pressure at surface will often drop dramatically.

9. Fracture Formation Pressure The Leak-off Test – Limit Test - Formation Breakdown Test

10. Fracture Formation Pressure The Leak-Off Test The “Leak-off test” is used to determine the pressure at which the rock in the open hole section of the well just starts to break down (or “leak off”). In this type of test the operation is terminated when the pressure no longer continues to increase linearly as the mud is pumped into the well.

11. Fracture Formation Pressure The Limit Test The “Limit Test” is used to determine whether the rock in the open hole section of the well will withstand a specific, predetermined pressure. This pressure represents the maximum pressure that the formation will be exposed to while drilling the next wellbore section.

12. Fracture Formation Pressure The Formation Breakdown Test The “Formation Breakdown Test” is used to determine the pressure at which the rock in the open hole section of the well completely breaks down.

13. Fracture Formation Pressure Example While performing a leak off test, the surface pressure at leak off was 940 psi. The casing shoe was at a true vertical depth of 5010 ft and a mud weight of 10.2 ppg was used to conduct the test. Calculate the maximum allowable mud weight.

14. Fracture Formation Pressure Example The Maximum bottom hole pressure during the leakoff test can be calculated from: hydrostatic pressure of column of mud + leak off pressure at surface = (0.052 x 10.2 x 5010) + 940 = 3597 psi The maximum allowable mud weight at this depth is therefore = 3597 psi / 5010 ft = 0.718 psi/ft = 13.8 ppg Allowing a safety factor of 0.5 ppg, The maximum allowable mud weight = 13.8 - 0.5 = 13.3 ppg.

15. Fracture Formation Pressure Surface Leakoff Pressure Calculation The anticipated surface leakoff pressure, Plo is given by: Plo = Pff – 0.052rD + DPf Where DPf is the frictional pressure loss in the well between the surface pressure gauge and the formation during the leakoff test. This equation is also used to compute the observed fracture pressure, Pff, from the observed leakoff pressure Plo. The pressure required to initiate circulation is obtained by equation:

16. Fracture Formation Pressure Surface Leakoff Pressure Calculation The anicipated slope line for the early leakoff test results is determined from the compressibility of the drilling fluid. The effective compressibility, ce, of drilling fluid composed of water, oil, and solids having compressibilities cw, co, and cs, respectively. ce = cwfw + cofo + fsfs Where fw, fo, and fw are the volume fractions of water, oil, and solids.

17. Fracture Formation Pressure Surface Leakoff Pressure Calculation Compressibility is defined as Therefore, the change in pressure due to the change in the volume of drilling fluid is

18. Fracture Formation Pressure Surface Leakoff Pressure Calculation Example: The leakoff test shown in Fig. 6.53 was conducted in 9.625’’ casing having an internal diameter of 8.835’’ which was cemented at 10,000 ft. the test was conducted after drilling to 10,030 ft the depth of the first sand with an 8.5’’ bit. Drillpipe having an external diameter of 5.5’’ and an internal diameter of 4.67’’ was placed in the well to a depth of 10,000 ft for the test. A 13.0 lbm/gal water based drilling fluid containing no oil and having a total volume fraction of solids of 0.2 was used. The gel strength of the mud was 10 lbm/100 ft2. Verify the anticipated slope line shown in Fig. 6.53 and compute the formation fracture pressure.

19. Fracture Formation Pressure Surface Leakoff Pressure Calculation

20. Fracture Formation Pressure Surface Leakoff Pressure Calculation

21. Fracture Formation Pressure Surface Leakoff Pressure Calculation

22. Fracture Formation Pressure Surface Leakoff Pressure Calculation

23. Hubbert and Willis Equation: They introduced a principle: the minimum wellbore pressure required to extend an existing fracture was given as the pressure needed to overcome the minimum principle stress Based on the experimental data from the laboratory, they suggested that the minimum principle stress in the shallow sediments is approximately one-third the matrix stress resulting from weight of the overburden Prediction of Fracture Pressure Hubbert and Willis Equation

24. Prediction of Fracture Pressure Hubbert and Willis Equation

25. Prediction of Fracture Pressure Hubbert and Willis Equation Example 1: Compute the maximum mud density to which a normally pressure U.S. gulf coast formation at 3000 ft can be exposed without fracture. Use the Hubbert and Willis equation for fracture extension. Assume an average surface porosity constant of 0.41, a porosity decline constant K of 0.000085 and an average grain density of 2.6 g/cm3.

26. Prediction of Fracture Pressure Hubbert and Willis Equation

27. Prediction of Fracture Pressure Hubbert and Willis Equation Formation pressure Fracture pressure

28. Prediction of Fracture Pressure Matthew and Kelley Correlation Matthews and Kelley Correlation Drilling experience showed that Hubbert and Willis method is not valid for deeper formation. Matthews and Kelley replaced the assumption that the minimum stress was one-third the matrix stress by where the stress coefficient was determined empirically from field data taken in normally pressured formations.

29. Prediction of Fracture Pressure Matthew and Kelley Correlation The vertical matrix stress at normal pressure is calculated (subscript “n” is for normal pressure) (sma)n = sobn – Pfn For simplicity, Matthews and Kelley assumed that the average overburden stress is 1 psi/ft and an average normal pressure gradient is 0.465 psi/ft. To calculate abnormal fracture pressure, they introduced the depth Di. Di is the equivalent normal pressure depth which represents for the abnormally pressured formation of interest depth.

30. Prediction of Fracture Pressure Matthew and Kelley Correlation At the depth at which the abnormal pressure presents:

31. Prediction of Fracture Pressure Figure 1: Equivalent normal pressure depth vs. Matrix stress ratio

32. Prediction of Fracture Pressure Matthew and Kelley Correlation Example 2: A south Texas gulf coast formation at 10,000 ft was found to have a pore pressure of 8000 psig. Compute the formation fracture gradient using Matthews and Kelley correlation.

33. Prediction of Fracture Pressure Matthew and Kelley Correlation From Fig 1, at Di = 3738 ft, Fs = 0.59 Note that one of the assumptions is that an average overburden stress gradient. Therefore, the overburden stress or vertical stress The fracture pressure gradient:

34. Prediction of Fracture Pressure Pennebaker Correlation The Pennebaker correlation is similar to the Matthews and Kelley correlation. Pennebaker called the coefficient Fs the effective stress ratio and correlated this ratio with depth, regardless of pore pressure gradient. Thus, the actual depth of the formation always is used in the Pennebaker correlation, which is shown in Fig. 6.48.

35. Prediction of Fracture Pressure Pennebaker Correlation

36. Prediction of Fracture Pressure Pennebaker Correlation Example: A south Texas gulf coast formation at 10,000 ft was found to have a pore pressure of 8,000 psi. seismic records indicate an interval transit time of 100 ms/ft at a depth of 6,000 ft. Compute the formation fracture gradient using the Pennebaker correlation.

37. Prediction of Fracture Pressure Pennebaker Correlation

38. Prediction of Fracture Pressure Pennebaker Correlation

39. Prediction of Fracture Pressure Pennebaker Correlation

40. Prediction of Fracture Pressure Christman Correlation Christman found that the stress coefficient could be correlated to the bulk density of the sediments.

41. Prediction of Fracture Pressure Christman Correlation Example 3: apply the Christman correlation to calculate the fracture pressure gradient based on example 1 and 2. Pore pressure 6500 psig

42. Prediction of Fracture Pressure Christman Correlation Bulk density From Fig. 2 Fracture pressure gradient

43. Prediction of Fracture Pressure Summary of Procedures When planning a well the formation pore pressures and fracture pressures can be predicted from the following procedure: 1. Analyse and plot log data or d-exponent data from an offset (nearby) well. 2. Draw in the normal trend line, and extrapolate below the transition zone. 3. Calculate a typical overburden gradient using density logs from offset wells. 4. Calculate formation pore pressure gradients from equations. 5. Calculate the fracture gradient at any depth.

44. Prediction of Fracture Pressure Summary of Procedures