14.1 Introduction to Hydraulic Fracturing.
Hydraulic fracturing is a process of creating a fracture by the injection of fluids into a
formation at a pressure higher than the parting pressure of the formation. Injection
rate has to be high enough and formation permeability to the injected fluid has to be
low enough that fluid loss is not excessive in which pressure can build up and
sufficient to fracture the formation or to open existing natural fractures.
Normally, proppants are injected with fluids to prop the fracture open in sandstone
formations, and acids are used to etch the fracture faces making them uneven to
prevent them from completely closing in carbonate formations. The propped or etched
fracture will act as high conductivity passage for fluids to move to the wellbore with
much ease.
Hydraulic fracturing has been used to accomplish four basic jobs:
1. Overcome wellbore damage (high permeability formations).
2. Create deep-penetrating fracture into reservoir to improve the
productivity or injectivity of a well.
3. Aid in secondary recovery operation.
4. Assist in the injection or disposal of brine and industrial waste material.
14.2 Candidate Selection.
All carbonate formations can be candidates for Fracture Acidizing treatments.
However, poorly performing wells due to low reservoir permeability and/or wells with
restriction due to damage near the wellbore are more suitable as acid fracturing
candidates.
Factors affecting well's productivity are:
1. Low reservoir permeability.
2. Damage in near-wellbore region.
3. Inefficient production equipment.
Well's productivity can be evaluated by:
1. Offset well comparison.
2. Production history curves.
3. Pressure transient analyses (buildup, draw-down, etc.).
4. Producing well system analysis.
5. List of damage indicators (well's report).
14.3 Acid-Fracturing Design Concepts.
In low to moderate-temperature wells, acid fluid-loss control may be the most
important consideration. In high temperature wells, effective acid penetration distance
often is limited by rapid spending, and retarded acid should be considered. In soft
formation, such as chalks, the treatment should be designed specifically to maximise
fracture conductivity.
As the acid flows along the fracture, portions of the fracture faces are dissolved. Since
flowing acid tends to etch in a non-uniform manner to create conductive channels
which usually remain open when the pumping pressure is released and the fracture
closes. The effectiveness of the acid fracturing treatment is largely determined by the
length of the etched fracture which is controlled by the volume of the acid used, acid
reaction rate, and the acid fluid loss from the fracture into the formation. When
designing an acid fracturing treatment, all factors affecting the success of the
treatment must be considered:
· Pre-treatment formation evaluation.
· Production system analysis.
· Rock mechanics and fracture geometry.
· Rock solubility (reservoir temperature).
· Acid penetration.
· Acid and additives.
· Lab tests.
The following goals are expected after an acid fracturing treatment:
· The fracture propagated across the pay zone.
· The acid dissolved a large amount of reservoir rock.
· The acid etched the fracture faces unevenly to create channels with
sufficient etched length and width that contained high conductivity after
the fracture closed.
· Rapid and complete recovery of the treating fluids.
· Large fold of increase at a reasonable cost
14.4 Acid Fracturing Design Considerations.
14.4.1 Pre-treatment Formation Evaluation
a. Geologic considerations.
· Lithology: Carbonate (limestone, dolomite).
· Drainage area
xf/re ratio.
Fault patterns.
· Well logs.
Porosity.
Net pay.
Water saturation.
Mechanical properties. (Young's modulus, Poisson's ratio).
Fracture height (temperature logs).
· Core analysis.
· Conventional core analysis.
Porosity.
Permeability (5 to 100 folds high).
Compatibility with stimulation fluids.
· Special core analysis (in-situ).
Permeability.
Porosity.
Relative permeability.
Capillary pressure.
· Oriented coring.
Natural fractures direction.
In-situ stress in three directions.
Fracture azimuth.
b. Well testing considerations.
· In-situ reservoir permeability.
· Skin factor.
· Reservoir pressure.
· Reservoir temperature.
· Reservoir fluid properties.
14.4.2 Production system analysis.
· IPR (flow in reservoir).
· Pressure drop across completion.
· Pressure drop in production string.
14.4.3 Rock mechanics and Fracture Geometry
a. In-situ stress:
· Fracture extension pressure
· Closure pressure
b. Basic rock mechanics and properties:
· Young's modulus (E) ( 8 to 13 x 106 psi for limestone and
dolomite)
· Poisson's ratio (u) ( 0.15 to 0.27 for limestone and dolomite)
c. Fracture geometry:
· Fracture height:
Upper and lower barriers (stress contrast)
Pump rate.
· Fracture models:
KGD.
PKN.
Radial.
· Fracture half-length:
Injection rate.
Leak-off rate.
Fracture height and width.
Volume pumped ($).
· Fracture width:
Formation hardness (Young's modulus).
Fluid viscosity.
· Fracture azimuth
Perpendicular to minimum compressive principal in-situ stress.
14.4.4 Rock Solubility
· Greater than 70%.
· Limestones, dolomites, chalks.
· No insoluble reaction by-products.
14.4.5 Acid Penetration.
· Acid injection rate.
· Leak-off rate (worm-holes).
· Acid concentration.
· Formation temperature.
· Fracture width.
· Reaction rate.
· Composition of the formation.
· Effect of viscous fingering.
· Cost $ (volume -up to a certain point).
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