Hydraulic Fracturing Measurement, Characterization and Analysis

Based on a PTTC Rocky Mountain Region workshop, May 27, 2004 in Casper, WY

BOTTOM LINE

Understanding the reservoir, its basic rock properties and how they affect fracturing, is a prerequisite for optimizing hydraulic fracturing treatments. Choosing the proper fracturing fluid, proppant, proppant load, and additives are important. Achieving and maintaining fracture conductivity is essential. Modeling, recognizing the underlying theory and limitations, can help operators determine how different parameters affect created fractures and guide them to treatment designs that will be more effective. Data gathered during a frac treatment provides insights for future frac designs. Some testing techniques provide indirect evidence of what is happening in the rock during a frac treatment, while other techniques such as tiltmeter or microseismic techniques directly measure the fractures that are being created. Fracture reorientation, which is now receiving renewed interest, creates restimulation opportunities.

PROBLEM ADDRESSED

For most reservoirs, effective well stimulation is required for attractive economics. This is particularly true for tight gas or unconventional reservoirs that are increasingly the target in domestic exploration. Determining when restimulation makes sense is also important in the vast number of existing wells/reservoirs. Hydraulic fracturing is a key stimulation technology, but for maximum effectiveness to be achieved, one must understand the underlying theory, how to design and model treatments, and how to analyze treatment data to determine what happened so subsequent treatments can be redesigned to be more effective.

KEY WORDS:

Barnett Shale, Fracture conductivity, Fracture fluids, Fracture reorientation, Hydraulic fracturing, Modeling, Rock properties

SPEAKERS

All Topics,
Dr. Jennifer Miskimins, Petroleum Engineering Department, Colorado School of Mines

TECHNOLOGY OVERVIEW

Fracturing Basics
A basic rock property of interest in hydraulic fracturing, Young's Modulus, E, can be measured using static (mechanical, triaxial) or dynamic (acoustic) techniques. Static tests are more accurate and expensive. Dynamic tests can measure "shale" information and get a lot of information for the entire zone, but there are resolution issues and "weaknesses" such as fractures or discontinuities affecting measurement. Young's Moduli measured by static and dynamic tests can vary significantly.

A reservoir rock is under three stresses-overburden stress that is about 1 psi/ft in most sedimentary basins, plus there are maximum horizontal and minimum horizontal stresses. It is critical to determine the orientation of the maximum horizontal stress since fractures parallel it. These fractures and the flow patterns they create influence the preferred orientation for perforations, affects the shape of drainage areas and well spacing, sweep efficiencies in flood projects, and the best orientation for horizontal wells. This stress or orientation can be measured by microfrac tests, mini-frac or G function tests, analysis of wellbore breakouts, inferred from geological/tectonic information or observed in oriented core.

In most petroleum applications, both the rock matrix and the pore pressure support a portion of the applied stress. The overburden or effective stress equals the matrix stress plus the pore pressure. Effective stress is different in drained and undrained rock. When load is applied instantaneously, rock behaves as undrained and stiff. When load is applied slowly, rock "drains," has time to diffuse and becomes "softer." Biot's constant, which is around 0.7 for most reservoirs (but assumed to be 1 in most hydraulic fracturing calculations), adjusts for this effect when calculating effective stress.

The Hydraulic Fracturing Process

There are generally five steps in the hydraulic fracturing process

• Injection of a pad (gelled water, no solids) to breakdown the formation
• Injection of a slurry (gelled water with proppant) to propagate and develop fracture
• Displacing the slurry to the formation (clear the tubing/casing)
• Shut down injection, allow leakoff and closure
• Followed by a flow back period to clean up

The big questions for hydraulic fracturing are:

• Design-What goes into designing a frac treatment?
• Modeling-What can't modeling tell you?
• Analysis-How do you analyze success of your treatment and improve it next time?

Geological and reservoir pre-treatment data of interest include: porosity, permeability, saturations, gas and water contacts, mineralogy, pressure, stresses, rock moduli, temperature gradients and well spacing. Pre-treatment planning should consider potential formation damage. Treatment parameters of interest include rates and pressures, fluid properties, proppant types and concentrations, and additives. There needs to be an evaluation of production potential.

Dimensionless fracture conductivity is a key parameter affecting fracturing effectiveness. It is dependent on fracture length, type of proppant, proppant size distribution and concentration in the fracture, stress load on the proppant pack, formation embedment characteristics, non-Darcy flow effects and potential plugging from frac fluid residue. One must recognize which factors can be controlled. Long-term degradation of fracture conductivity can occur from polymers, embedment, crushing, fines, scale and paraffin/asphaltenes.

Fracturing Fluids

• These fluids are likely the most expensive physical component of a fracturing treatment. They can be water-based, oil-based, acid-based or foams. Ideal properties are:
• Adequate viscosity to suspend and transport proppants, initiate and create fracture width, and control settling and banking.
• Good fluid loss control since high fluid loss may reduce frac length and may result in screenout.
• Low residue since high residue will reduce fracture conductivity, degradable to avoid plugging. Generally low residue = high cost.
• Low friction pressure since friction = cost. Delaying cross-linking reduces friction.
• Temperature and shear stable throughout the treatment, testing in both laboratory and field samples to evaluate stability.
• Non-damaging to the formation (a myriad of factors).
• Easy to mix in the field. Take care to avoid fish eyes, bacterial degradation, contamination and iron interference. Consider using a liquid gel if good mixing is not available. Always have a good QC program.
• Easy to recover, breaking to low viscosity by thermal degradation or other breakers for easy removal.
• Cost effective

Modeling

Fracture modeling can use either 2D or 3D approaches. 2D modeling assumes a constant height, predicting width and length. Since experience indicates height growth occurs in many reservoirs, this is a limitation of 2D modeling that leads to overly optimistic fracture lengths and poor proppant transport predictions. 3D modeling using finite element or boundary integral methods can be more accurate, but more input data is needed. 3D modeling matches both pressure behavior and fracture geometry. In modeling, one must understand the assumptions in the model and recognize that the modeler has significant control of the outcome and answers are non-unique. I.e., experience is invaluable in modeling fracs.

Measurement and Characterization

Testing to understand and evaluate created fractures falls into three basic categories-pre-treatment testing, indirect testing, and direct testing.

Pre-Treatment. Step-rate tests can help determine whether perfs are open and the degree to which tortuosity causes high near-wellbore friction losses. Tortuosity reflects the complex connection between the wellbore and the fracture(s). Excess tortuosity can lead to near wellbore screenouts. G-Function analysis is a technique used to describe fracture pressure decline behavior. It is used to measure closure pressure, leak-off characteristics and can provide an in-situ permeability measurement. When gathering data, one must allow enough shut-down time for closure to occur. G-Function testing is attractive because it is performed onsite just prior to the treatment. Compared to conventional well testing techniques, which can require very long shut-in times in tight reservoirs, it is time effective.

Indirect Testing. Log-Log plots (log net fracturing pressure vs. log time) provide real time indicators of what is happening with the fracture (confined height and extending, limited extension, screenout, unwanted height growth). Specialized pressure transient analysis techniques can measure important parameters such as kh, effective xf, and effective drained area.

Direct Testing. Temperature logs and radioactive tracers are near wellbore measurements only. Tiltmeters, which can be either surface, downhole in offsets or in the treated wellbore itself, are not limited to the near wellbore region. Tiltmeters measure minute deflections that result from created fractures. Similarly, microseismic techniques measure the micro-earthquakes that occur with fracturing. Tiltmeter and microseismic techniques provide critical data on orientation, fracture complexity and fracture length.

Fracture Conductivity

API conductivity tests (RP 61, Recommended Practices for Evaluating Short Term Proppant Pack Conductivity) are misleading, for a variety of reasons. For one thing, RP61 recommends superficial velocities of 0.2 to 2.0 inches per minute while actual velocities in fractures may exceed 2 feet per second. Two other key reasons are non-Darcy flow effects and multiphase flow. All these factors can cause the effective fracture half-length to be significantly less than predicted.

Fracture Reorientation

Pore pressure depletion alters stress state, affecting maximum horizontal stress more than minimum. If the change in pore pressure is more than original difference in max/min, then the orientations will switch. Offset stress changes (i.e., new offset well) can reorient max/min stresses. Reorientation of 30 to 40 degrees is typical. As the fracture exits the perturbed region, it will return to original orientation. This reorientation effect creates restimulation opportunities, as noted in the Barnett Shale below. Opportunities likely exist in other reservoirs.

Evolution of Hydraulic Fracturing in Barnett Shale

The Barnett Shale in the Fort Worth Basin is an unconventional gas play. In-place resource is very high, some 160 Bcf per square mile, but the reservoir is tight and drainage areas are small. Hydraulic fracturing is essential. Although initial development began in the early 1980s, activity did not really boom until the last few years as completion and hydraulic fracturing techniques evolved and gas prices remained strong. Early fracs were gelled water, beginning with 250,000 gals gelled water and 300,000 lb proppant in the early 1980s and increasing to a million gallons gelled water with a million lb proppant. Operators began switching to "slick water" fracs in the late 1990s to minimize gel damage, develop longer more complex fractures, and lower cost. Current treatments may be 750,000 gal or more with low proppant loads of only 0.1-0.5 ppg. Fracturing fluids are reused. Costs range from $80,000 to $160,000. Operators have discovered that refracing a few years after completion is profitable, as the new fracs have a different orientation than original fractures and new reservoir is accessed.

Selected SPE Paper References (accessible online through www.spe.org)

• SPE #84306 (2003), "Realistic Assessment of Proppant Pack Conductivity for Material Selection"
• SPE # 75359 (2001), "Diagnostic Techniques To Understand Hydraulic Fracturing: What? Why? And How?"
• SPE # 56600 (1999), "Estimating Pore Pressure and Permeability in Massively Stacked Lenticular Reservoirs Using Diagnostic Fracture-Injection Tests"

CONNECTIONS:

Dr. Jennifer Miskimins, PE
Colorado School of Mines
Petroleum Engineering Department
Golden, CO 80401
Phone: 303-384-2419
E-mail: jmiskimi@mines.edu

For information on PTTC’s Rocky Mountain Region and its activities contact:
Sandra Mark, Director, Colorado School of Mines
Department of Geology and Geological Engineering, Golden, CO 80401-1887
ph 303-273-3107, fax 303-273-3859, e-mail smark.95@alum.mines.edu

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