Stimulation Study of Cottage Grove Formation
Authors: Elbel J.L. , Howard R.L. , Talley G.R. , McLaughlin B.H. 
Published: December 2007

Summary
Bottomhole pressure (BHP) monitoring during hydraulic fracturing treatments can provide data that permit better job control as well as improved design for future treatments. Data collected by this method during a recent study of the Cottage Grove formation in Dewey County, OK, indicated fracture growth through barriers and also tip screen out. This provided a basis for changes in sand scheduling during treatment and in design of subsequent treatment. Stressmagnitude in the pay zone and adjoining barriers, rock properties, and fracturing-fluid leakoff coefficients were determined. It is shown that careful analysis of pressure during a treatment can be a useful tool in better design and application of fracturing treatments.

Introduction
Hydraulic fracture stimulation has been used to increase production rates in many reservoirs. In designing a production rates in many reservoirs. In designing a fracture treatment, certain parameters, particularly fracture height and fluid loss, are critical in obtaining a reasonable estimate of fracture geometry from computer simulations. Proper blending of additives is also critical to achieve the designed geometry.
A study of fracturing treatments was initiated to determine these parameters more accurately and to evaluate fracture treatments by use of new treatment-monitoring capabilities and recent theories. This study was not intended to be a thorough or complete research project but was done to determine the merits and application of new theories and technology with little interference to normal completion operations.
This study involved 10 wells in the Cottage Grove formation, Dewey County, OK. Fig. 1 shows the gamma ray logs of the wells with the perforated interval and the interval of core samples analyzed from two wells.
A computerized treatment-monitoring unit was used to monitor the hydraulicfracture treatments on six wells. The treatments were injected down atubing/casing annulus with pressure recorded on the static tubing line, which gives a reflection of the bottomhole treating pressure (BHTP). Flow meters were placed in the pressure (BHTP). Flow meters were placed in the liquid-additive lines, tachometers were placed on each pump truck pumping slurry, and two downstream densitometers were placed on the treating lines near the wellhead to measure slurry density. Transducers at these locations allowed the computerized unit to record all data and to make the necessary calculations to determine the blending ratios continuously. All liquid volumes and proppant weights weregauged in the tank before and proppant weights were gauged in the tank before and after the treatment for comparison with those measured and calculated by the monitoring unit. There were good comparisons between measured and calculated volumes.
Table 1 describes a typical completion and fracturing procedure. The additional steps required for this study procedure. The additional steps required for this study were the stress test, Step 7, and the minifracture and fluid-loss calculation, Step 8. Step 8 was not performed on all treatments. On the last well treated, a temperature survey was made after Step 7 and after the treatment.
The formation and fracturing-fluid parameters that were obtained formed the basis for design changes, and the real-time BHP monitoring enabled procedure modifications during the treatments.

Minimum Horizontal Stress
The minimum horizontal stress was determined by plotting and interpreting pressure falloff after a short period plotting and interpreting pressure falloff after a short period of injection. On the Sue No. 1, an injection rate of about 7 bbl/min [ 1.1 m 3 /min] with a surface injection pressure when measured on the static tubing side of 600 psi [4.14 MPa] was maintained for about 2 minutes (Fig. 2). The instantaneous shut-in pressure (ISIP) was about475 psi [3.27 MPa]. This was repeated a second time with nearly identical results. Various types, of plots of the pressure falloff were made-i.e., p vs.t; log delta p vs. log deltat; and p vs. log (t + delat t)/delta t. p vs. log(t + delat t)/delta t. For permeable formations, the first two plots show a straight line when the flow of fluid causing leakoff is linear, and the third plot shows a straight line when flow is radial. When the fracture is open and the fluid leakoff is into the matrix along the fracture face, the flow is linear. After the fracture closes, the flow from the wellbore through the matrix should be radial. These plots are shown in Figs. 3, 4, and 5, and indicate the change from linear to radial flow to be approximately 200-psi[1.38-MPa] surface pressure as compared with the ISIP of 475 psi [3.77 MPa].This represents a minimum horizontal stress of 3,940 psi [27.17 MPa] for a gradient of 0.46 psi/ft [10.4 kPa/m]. Similar tests were performed on other wells (Table 2). These tests were performed on other wells (Table 2). These tests were performed after acid breakdown and after some short performed after acid breakdown and after some short periods of production. On some tests, the wells would be periods of production. On some tests, the wells would be on a vacuum after injection of small volumes, 10 to 20 bbl [1.6 to 3.2 m 3 ] fluid, but after about 30 to 40 bbl [4.8 to 6.4 m3] were injected, the pressure decay would be normal. It appears that the short production reduced the pressure near the wellbore enough to affect the
JPT
P. 1199