The critical well in a field development needs to have a fracture design. What data is important to generate a good design? How would you go about generating the design? This Frac Tips is general overview of the required information, where it is obtained, and how it is utilized to generate treatment designs.
The most important information to know or obtain is reservoir permeability. Permeability can be obtained from pressure build up tests, core measurements or nodal analysis. A pressure build up test can be used to determine reservoir pressure. Pressure can also be obtained from a direct measurement after perforating. Permeability and reservoir pressure can also be measured from the decline data after an injection (min-frac) test. A high permeability well might be designed with a tip screen out (TSO) where a low permeability well would need a long, lower conductivity fracture. For more information on whether a long, skinny fracture or a short, fat fracture is needed, please see the Frac Tips “Optimum Fracture Design.”
Reservoir porosity can be obtained from log measurements or core testing. Formation temperature is measured from logs. The production fluids (oil, gas, water) and their saturations can be calculated from logs and from core data.
The reservoir geology can also have a major effect on fracture design, primarily through drainage area. Treatment execution can be impacted by geologic features such as faults, unconformities, and fractures. Ignoring this information can have disastrous results. A visit with your friendly local geologist is always a good idea when designing a treatment in a new area!Reservoir Fluid Properties
The reservoir wetting phase (oil or water wet) can be determined from core information or inferred from production in the same reservoir. Oil gravity, gas gravity and percentage of impurities ( CO2, N2, and H2S ) can be determined from laboratory measurement of fluid samples. The production yield (gas perbarrel or barrel per mcf) can be measured or estimated from other known reservoirs in the area.Rock Properties
A lithology log (usually Gamma Ray or SP) is critical to identify the formation layering (sand, silt, shale, etc.). The Young’s modulus of the rock can be determined from core laboratory measurements or inferred from measurement of compressional travel time. For more information, please see the Frac Tips ”Rock Mechanics For Fracturing”. Laser particle size or sieve analysis of core samples from the producing formation can yield data about formation size distribution and fines migration potential for “soft” formations.
There are many choices of fracturing fluids and proppants. A fracturing fluid should be chosen based on reservoir permeability as well as temperature and wettability of the formation. The fluid chosen should yield an efficiency of at least 10%. If less then a system with better fluid loss control should be selected.
The fluid should be tested with a viscometer using the chemicals from the field area and the local source water being used. Breaker schedules should be developed and tested in the laboratory, and confirmed in the field.
The proppant is selected based on the effective proppant stress, availability in the field, and price. A major consideration for proppant selection will be formation permeability and the “need” for fracture conductivity. This dependence on desired fracture conductivity, kFw, and formation permeability can be seen from dimensionless conductivity, FCD, where a desirable FCD is always at least 2 (> 2 may be desirable for lower permeability zones where transient flow is important).
Proppant stress can be calculated with Equation 2 where ∆ is incremental stress due to the propped fracture width. ∆ is usually small (200 to 400 psi) but can be significant in some cases such as TSO (tip screenout) treatments in a moderate permeability, “hard” rock. Pwf is bottom hole flowing pressure.
A rate accelerated well was drilled into a partially depleted low water drive gas reservoir. The reservoir is a large anticline structure and is fault bounded on one side. Reservoir properties can be found in Table 1. A core was taken in the first well and tested yielding a modulus of 1.0x106 psi in the sand and 1.5x106 psi in the shale. Poisson’s ratio in the sand was 0.25. The core showed the sand was not friable, so fines were not expected to be an issue. The well was located far from the fault, and was a non-deviated hole with 7” casing set to TD. It was logged with a triple combo log (see Fig. 1). A previous frac showed there were no tectonic effects, i.e., a “normal” closure stress. The sand stress was calculated to be 4,743 psi at the top of the pay zone with a fracture gradient of 0.59 psi/ft. The shale was calculated to have a closure stress of 4,886 psi at a depth of 7,856’ with a fracture gradient of 0.62 psi/ft. A 30 lb/1000 gal low guar gel system was chosen from the results of the previous frac yielding a leak off coefficient of 0.003 ft/√min, thus yielding an efficiency of 20% after a 7,000 gallon minifrac.