HBL FracPac Completion Service

Chapter 2 INTRODUCTION Formations that are considered soft or poorly consolidated are often plagued by sand production tendencies. Formation sand production results in lost production and plugged gravel packs, screens, perforations, tubulars, surface flow lines, and separators. In addition to damage caused to surface equipment by plugging, casing and surface equipment can erode due to abrasive, sand-laden fluid flow from the well. Worst-case sand production problems can cause total well failure or the need for recompletion from casing collapse, openhole collapse, or both. Conventional treatments for sandproducing wells include gravel packing,

sand consolidation, and resin-coated sand slurries. These treatments minimize the effect of sanding and are based on gravel-packing technology, which bridges the produced fines. This restrictive or filtrative nature of the gravel pack is effective for a while, but over time the permeability of the pack decreases. Permeability damage to the pack causes a high, positive skin in the near-wellbore area, which may cause a tremendous decrease in well productivity. Figure 2.1 shows the effect that sanding has on a gravel pack.

Rock Mechanics and Sanding Tendency

Fracturing high-permeability reservoirs has now gained wide acceptance as an effective method by which to control

Productivity

Profile of Well Requiring FracPac Services

Normal Decline Apparent Gravel Pack Failure

FracPac Treatment

Regravel Pack

Time

Figure 2.1 — The normal production decline of a well is shown by the red curve. The production decline of a well treated with a conventional gravel pack is depicted by the solid black curve. Even after a second application of gravel packing is performed, the gravel pack plugs with sand and the well’s production declines quickly. The dashed curve denotes the production decline after a FracPac treatment. Productivity is drastically improved initially, and the production decline parallels the normal decline thereafter.

5

FRACPAC COMPLETION SERVICES

sanding and to bypass near-wellbore damage, stimulating production. From a rock mechanics perspective, this chapter focuses on the benefits of performing FracPac Completion Services for stimulation, sand control, or both. Topics such as drawdown, in-situ stresses, failure mechanisms, sanding-tendency prediction, tip-screenout fracturing, and fracture behavior are discussed in detail and show how FracPac procedures can help overcome production problems caused by sanding.

DRAWDOWN DUE TO FLUID FLOW A high production rate from a highly permeable reservoir causes a high drawdown across the formation in the vicinity of the wellbore. This drawdown places increased deviatory stress on the formation, which, if it exceeds the strength of the formation, can cause formation failure and resulting sand or fines production. It is important to understand the pressure-drawdown components that contribute to the overall pressure drop that occurs in the proximity of the wellbore. In addition to the energy loss in Darcian flow, the drawdown must overcome the following flow impairments: • Radial flow convergence, momentum effects, and permeability damage from the near-wellbore stress field induced by drilling • Wellbore flow impairment, such as partial penetration, perforation, and skin damage • Damage farther into the formation caused by drilling mud and fines invasion (damage from drilling and production) The factors listed previously contribute to a large drawdown within a small area adjacent to the wellbore. In addition to the pressure disturbance acting on the fluid in the pores of the formation, a near-wellbore mechanical stress-concentration zone is created, which will be discussed in detail later in this chapter. The effective stress on the formation (the total stress minus the pore pressure) increases significantly near the wellbore, and with this, the risk of formation failure rises during the early stages of production. Formation failure can still occur at a later time as the reservoir is depleted by production; however, if the drawdown is eased at the wellbore, a more stable stress field occurs. Reducing drawdown is one of the major objectives when performing FracPac Completion Services.

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FracPac Completion Services are designed to create short, wide, and highly conductive fractures that bypass nearwellbore damage, creating a channel from the undamaged formation to the wellbore. Bypassing the near-wellbore damage helps to decrease the drawdown at the wellbore for a given production rate. Two parameters that control the production increase of a well that is hydraulically fractured are fracture conductivity (kf bf ) and fracture half length (Lf ). Reservoir permeability (k) also must be considered when fracturing a well. The dimensionless fracture conductivity (Cf D ) combines the effect of fracture conductivity, fracture half length, and permeability into one formula: kf bf . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2.1) Cf D kLf where kf bf is fracture conductivity (md-ft), k is reservoir permeability (md), and Lf is fracture half length (ft). Computer simulations of hydraulically fractured reservoirs, such as those shown in Chapter 4 (Reservoir Engineering) indicate that in low-permeability reservoirs, production can be increased by increasing the fracture length. In high-permeability reservoirs, however, short fracture lengths with high conductivity can be effective. The reservoir engineering chapter also discusses how it is very important to determine the pressure profile throughout an entire drainage area to be able to design a FracPac treatment with the following parameters: • The fracture length required to bypass the wellbore damage and prevent the severe pressure drop (this parameter is optimized for either sand control or stimulation) • The fracture conductivity required to minimize the pressure drop near the wellbore A FracPac treatment must be carefully designed with a clear objective: either sand control or stimulation. Although it is possible to accomplish both, priorities should be set early in the design process to ensure best results.

IN-SITU STRESSES AROUND THE WELLBORE The in-situ stresses within a reservoir are usually in equilibrium, which allows an undisturbed, stable condition to exist. If, for any reason, the in-situ forces change and disturb the stability of the reservoir, a natural

This section focuses on the differences between a compentent sand and a friable sand, even though both can result in sand production. In competent sands, a stress concentration around the wellbore may produce a shear failure and result in sand production, and continuum mechanics can be used to describe the problem. However, in poorly consolidated or friable formations, this principle cannot be applied.

σvert (Overburden)

correction will occur as an attempt to regain natural stability. The in-situ stresses within a reservoir can be represented by three principal stresses: overburden or vertical stress (v ), minimum horizontal stress (h ), and maximum horizontal stress (H ). Figure 2.2 provides a diagram of the in-situ stress relationship. These principal stresses act on the reservoir rock and can change in magnitude around the wellbore, causing a stress-concentration zone. Stress-concentration zones can surpass the yield strength of weak or poorly consolidated formations and cause them to fail. The severity of the stressconcentration field and the resulting failure mechanisms are governed by the formation’s mechanical properties. Understanding the mechanical properties of the formation is essential in choosing the correct model for predicting the failure mechanisms that cause formation sands to move, and subsequent sand production.

Z σHor. Y X

σHor.

Figure 2.2 — The principal stresses act in orthogonal directions to one another. This relationship can be expressed on an X, Y, Z coordinate system. The overburden stress acts along the Z axis parallel to an imaginary line struck between the center of the wellhead equipment and the center of the earth. The other two principal stresses, known as horizontal stresses, act along the X and Y axes.

wellbore and the reservoir pressure determine whether or not the borehole collapses (wellbore breakout) or fracture initiation occurs.

Competent Sand Drilling a circular wellbore through a competent sand redistributes the in-situ stresses in the formation and creates a new stress field around the wellbore. If the wellbore is drilled into a linearly elastic, homogeneous, isotropic formation, after introducing a vertical wellbore into the reservoir, the stress state around the wellbore is given by 1 rw2 1 4rw2 3rw4 rr 1 ( ) 1 h 2 r2 2 H r2 r2

rw2 cos2 p . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2.2) r2

1 rw2 1 (H h ) 1 (H h ) 2 r2 2

3rw4 rw2 1 cos 2 p . . . . . . . . . . . . . . . . . . . . . . . . (2.3) r2 r2

The p represents the difference between the wellbore pressure and the formation pressure. The stresses near the

Wellbore Breakout (Borehole Collapse) A breakout zone may occur near the wellbore due to the stress concentration induced by drilling a wellbore. This breakout zone is created by shear failure of the formation, which follows a dilation of the borehole. The breakout is a naturally occuring event that relieves a stress concentration where the tangential stress ( ) exceeds the in-situ compressive strength. Although breakouts relieve the immediate stress concentration within the borehole, they can evoke sanding when the well is put on production. The well should be evaluated to determine whether or not it underwent a breakout failure mode during drilling. Wellbore breakout can adversely affect a FracPac treatment by hindering fracture initiation of a single, planar fracture which is critical to the success of FracPac. If breakout has occurred, a precise design of the perforating program becomes crucial and Halliburton recommends the following: 1. The near-wellbore area should be consolidated prior to fracture initiation. Consolidation can be performed by injecting a liquid-resin material into the payzone. The liquid-resin material increases the cohesion

7


among the particles of the formation sand. An array of consolidation chemicals has been tested and approved in Halliburton’s Rock Mechanics Laboratory and are available for such injection treatments. 2. The breakout zone is generally oriented in the direction of the minimum horizontal stress, therefore a 180°-phased perforating program should be performed. The perforations should be oriented in the direction of maximum horizontal stress, that is, the direction of the induced fracture. 3. To ensure that a planar fracture is created, the maximum allowable pumping rates should be used with a high-efficiency, viscous treating fluid.

Fracture Initiation Fracture initiation is a tensile failure mechanism that occurs when the borehole is pressured, which causes the tangential stress to become negative and become equal to the tensile strength of the formation. The following failure criterion describes the tensile failure mechanism: pwf t . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2.4)

Friable Sand Friable sands are usually cohesionless, and their mechanical properties are stress dependent. The state of stress around the wellbore may not conform to the theories of linear elasticity and continuum mechanics. A zone may develop around the wellbore that is stressed within plastic yield limits, thus making the contrast between the minimum and maximum horizontal stresses negligible. Formation failure within this plastic zone is a main source of sand production from the formation. As the plastic zone increases in size, sand production continues. Friable sands exhibit nonlinear characteristics, and it is believed that such sands should be evaluated differently than competent sands. Many mechanisms become important when evaluting nonlinear, friable sands. Some of these mechanisms are • Dilation • Capillary effect • Cohesive failure Once a wellbore or a perforation tunnel is introduced into a friable sand formation, a plastic zone develops and formation failure follows, usually because of one of the mechanisms mentioned above. 8

Production and cyclic loading are the main reasons that the plastic failure zone expands into the formation. To prevent the expansion of the plastic failure zone in friable sands, a circular tunnel (perforation or wellbore) should not be introduced to the formation. Instead, another method to deplete the reservoir should be considered, which is discussed later in this chapter.

FAILURE MECHANISMS Before a well can be effectively treated for sand production, the failure mechanisms that cause sand production should be understood. Two types of failure are most common: mechanical failure due to stress effects and formation failure due to chemical effects.1

Mechanical Failure Due to Stress Effect Drilling a wellbore through a formation of rock and sands introduces a new set of stresses to the area around the wellbore. The magnitude of these new stresses may be great enough to cause the formation to fail. Also, during the course of drilling, completing, or workover operations, the wellbore is actively and passively loaded with fluids and pressure, which can initiate formation failure. When the formation stress model is viewed as a system of polar coordinates, shearing stresses are imposed on the formation by a combination of vertical stress, tangential stress, and radial stress. Any combination of vertical, tangential, and radial stresses can contribute to sand production. If the bottomhole pressure is increased (passive loading), the radial stress will increase and the tangential stress will decrease. Should the tangential stress decrease enough, it will change from compression to tension. Most sedimentary rocks can withstand massive amounts of compressive force but fail when exposed to even slight tensile force. As a tensile failure occurs, cracks begin to open. If bottomhole pressure is decreased (active loading), such as when the mud-column weight is lowered or the well is put on production, the tangential stress in the wellbore will increase and the radial stress will decrease. Large drawdown at the wellbore can cause the tangential stress to exceed the strength of the formation matrix. Formation sand particles then begin to flow with the well fluids being produced. Eventually, such sand flow can cause serious problems, such as plugging gravel packs, plugging and eroding production hardware, and sometimes eventually rendering the well inoperable.

The stress effects previously discussed drive four failure mechanisms that cause the production of formation sand particles. Figure 2.3 depicts the four failure mechanisms that cause sand production: tensile failure, shear failure, cohesive failure, and pore collapse.

The Four Failure Mechanisms Shear Stress τ

σ1

➋ Shear σ3 Failure

Tensile Failure The effective stress at the wellbore exceeds the tensile strength of the formation and causes tensile failure if the following condition is true: pwf p t . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2.5) where pwf is bottomhole pressure, p is reservoir pressure, is effective tangential stress at the wellbore, and t is tensile strength (equal to zero when natural cracks exist). If the drawdown near the wellbore exceeds the tensile strength of the formation, tensile failure will result if

➌

Unstable

➊

θ

Cohesive Failure (C = τo)

Initial Conditions

➍

Tensile Failure

Stable

Pore Collapse Failure

To Tension

Co + Compression

Effective Normal Stress σ

Figure 2.3 — The four mechanisms that cause sand production are tensile failure, shear failure, cohesive failure, and pore collapse. The graph shows shear stress ( ) versus effective normal stress ().

pw t . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2.6) Where pw is the pressure differential at the wellbore and t is the formation tensile strength. This tensile failure condition may occur when the production rate is high enough to create a drawdown in the area local to the wellbore and is high enough to part the formation. Therefore, the production rate should be limited so that the drawdown near the wellbore does not exceed the tensile strength of the formation. FracPac technology can be applied in situations such as this to produce more hydrocarbon at a maximum sand-free production rate. Evaluating the formation to properly define the purpose of any FracPac treatment is essential to the success of the treatment. The Halliburton Rock Mechanics Lab is equipped to evaluate the mechanical properties of a given formation so that the correct FracPac treatment is performed.

Shear Failure Rock failure can cause a reduction in hole size due to plastic deformation of the formation. Failure can also cause hole enlargement in brittle formations that are prone to spalling. Once a wellbore is drilled and the stress-concentration field around the wellbore is established, the formation will respond either elastically (strong formation) or it will yield (weak formation). If the formation yields, a plastically

deformed zone begins to develop near the wellbore. This yield is a formation failure caused by the shear stresses exerted around the wellbore. Once shear failure has occurred, both large and small solids will be freed as the formation deteriorates at the failure plane. Figure 2.3 depicts a graph of shear stress ( ) versus effective normal stress (). The shear strength of a formation is represented by a straight line on this graph. The slope of the line is the internal friction of the formation. The intercept of the line with the shear stress (Y) axis represents the cohesion among adjoining sand grains of the formation. If this intercept is extrapolated in the direction of increasing tension, its intercept with the effective normal stress (X) axis indicates the tensile strength of the formation. The Mohr-Coulomb failure criterion can be used to predict failure conditions for a given formation. This criterion postulates that failure occurs when the shear stress at a given plane within the rock reaches a critical magnitude given by

coh n tan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2.7) where is shear stress, coh is cohesive strength or cohesion, n is normal stress, or the stress normal to the shear failure plane, and is the angle of internal friction.

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Failure Envelope for a Poorly Consolidated Sand Formation

α τ

Techniques for dealing with core samples of formations have been developed, and data analysis is performed to design a specific treatment for a candidate well. The Halliburton Rock Mechanics Laboratory has constructed the Mohr’s circle failure envelopes of many poorly consolidated formations around the world. Figure 2.4 shows a failure envelope for a poorly consolidated formation where the shear angle () was determined after the sample failed under compression.

Cohesive Failure

0

2,000

4,000 6,000 8,000 10,000 12,000 Normal Stresses (psi)

Figure 2.4 — The sample represented by this graph failed under compression. A failure envelope was developed, and the shear angle () was determined.

Coulomb-Mohr Failure Criterion τ = C + σn tan φ

τ

Failure

φ Friction Stable Cohesion

Tension 0

σn Compression

Figure 2.5 — The shear strength of the formation consists of two components: the contact forces between the grains, or friction, denoted by the magnitude from the red dashed line to its intersection with the shear failure line (blue), and the physical bonds between adjoining grains, known as cohesion. Cohesion is the magnitude shown from the X axis to the red dashed line.

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The cohesive failure mechanism is especially important when formations of poorly consolidated sands are to be stimulated with FracPac treatments. The cohesive strength (coh ) is the controlling factor of erosion at any free surface within the formation. These free surfaces occur at the perforation tunnels, at the wellbore face in openhole completions, at the surface of induced hydraulic fractures or induced shear planes, and at the surfaces where the pay zone contacts boundary intervals or the cement contacts the formation. As shown in Figure 2.5, the shear strength of the formation consists of two components: the physical bonds between adjoining grains, or cohesion, and the contact forces and friction between the grains. Cohesion is generated by two factors: cementing material and capillary forces among the grains of formation sand. Sand production and subsequent wellbore instability begin when the drag force caused by fluid production becomes great enough to exceed the cohesive strength of formation sand. Based on a 1-foot deep perforation tunnel into the formation, sand may be produced if dp coh . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2.8) dr The value coh is determined by extrapolation of the Mohr’s envelope to zero stress. This type of cohesive failure is responsible for generating small formation sand particles known as fines. Low cohesive strength is the reason for the start of sand production when a pressure drop near the wellbore is high. At the near-wellbore area (within 1 foot of the borehole), the pressure drop equal to the cohesive strength of the formation material defines the critical production rate without sanding. The rock mechanics team at Halliburton has developed techniques to determine the cohesion factor. Based on the results of cohesion-factor tests, a recommendation for either resincoated proppant or other proppant can be made. The cohesion factor can also be used to decide whether a screen should be used with the FracPac completion.

Pore Collapse

Pore Collapse Failure Mechanism

T p . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2.9) where p is reservoir pressure, is effective stress, T is total stress, and is Biot’s constant (factor that accounts for the deformation of the rock framework and subsequent inefficiency in the transmission of pore pressure). The effect of pore pressure in counteracting the confining pressure is reduced when inefficiency occurs in the transmission of pressure among the pores. The concept of effective stress implies that there is no porosity change under equal variation of pore pressure and confining pressure. When a FracPac treatment is being designed, the factor α may be required by the fracture design model. Techniques have been developed to determine the α factor.

Shear Stress (psi)

The definition of effective stress as the difference between total stress and pore pressure is given by

ea Sh

ee ilur r fa

pe n vel o

Pore Collapse

Normal Stress (psi)

Figure 2.6 — The pore collapse mechanism shows that when pore pressure decreases, the effective stress increases. When the effective stress increases, it causes the Mohr’s circle to move to the right, which may be bounded by a pore collapse failure cap, as shown by the dashed portion of the blue curve.

The Coulomb failure criterion is expressed in terms of the effective stress as follows:

coh (n pp) tan . . . . . . . . . . . . . . . . . . . . . . . (2.10) A graphical depiction of the pore-collapse mechanism is shown in Figure 2.6. When the pore pressure decreases, the effective stress increases. When the effective stress increases, it causes a Mohr’s circle to move to the right, which may be bounded by a pore-collapse failure cap. Once pore failure occurs, the damage is permanent and cannot be repaired. Hydraulic fracturing is a technique that can be used to bypass this damaged region and get a well back on production. In many cases this technique may be more attractive than abandonment or drilling another well.

Formation Failure Due to Chemical Effect The main mechanism of formation failure may be due to effects caused by chemicals that are introduced to the formation. Engineers may try to model failure mechanisms of unconsolidated reservoirs using nonlinear elastic models, elastoplastic models, and poroelastoplastic models, only to arrive at erroneous conclusions, especially if failure was caused by chemical effects. Water adsorption at the clay surfaces of a rock formation can cause an increase in bulk volume and subsequent swelling pressure if expansion is restricted. This swelling pressure can break the adhesive bond of the formation and disintegrate the formation matrix. Bulk volume and

resultant swelling varies in different types of formations. Water within the pore spaces of the formation can affect the formation in three ways: • It can reduce the magnitude of the internal friction. • It can reduce the capillary pressure for water-wet rocks. • It can chemically weaken the cementation material of the formation. Experimental data from Halliburton Rock Mechanics Laboratories show that water affects the compressive strength and elastic properties of rocks. For example, the softening factor (Fsoft ) is defined as the ratio of compressive strength of a dry sample to that of a wet sample. This softening factor was calculated from a sandstone sample known to be poorly consolidated and is given by coh (dry) 1,799 Fsoft 5.3 . . . . . . . . . . . . . . . . . (2.11) 335 coh (wet) The cohesive strength of the dry and wet samples were calculated and

σcoh (dry) ≅ 210 psi σcoh (wet) ≅ 0 to 20 psi

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Scanning electron microscope (SEM) and X-ray diffraction analyses can help determine the cementing materials such as calcite, dolomite, illite, mixed-layer clay, chlorite, and others. Any chemicals that could cause the formation’s cementation to deteriorate should not be introduced to the formation. Based on the SEM and Xray diffraction analyses, two important conclusions with respect to the problems of wellbore instability and sand production have been formulated:

bypass the near-wellbore damage, producing a more elliptical flow pattern and helping reduce the near-wellbore drawdown during production.

• Hydrochloric acid (HCl) used as a stimulation fluid may adversely affect the strength of the formation, if the cementation material is a carbonate. If the carbonate is dissolved, the rock structure can fail and cause solids production. Tests performed at Halliburton’s laboratories suggest that carbonate may be the cementing materials of some sandstone formations.

In-Situ Mechanical Properties

• If an appreciable percentage of the rock mineralogy is clay, the formation should be treated as potentially water sensitive. Swelling of clay affects the stability of the rock and indirectly affects sand production. Therefore, before a FracPac treatment is designed, the formation should be evaluated for potential formation failure from chemical effects. Evaluation for possible chemical effects allows for a more effective stimulation treatment to be designed.

SANDING TENDENCY AND SAND PREDICTION Methods for predicting sanding tendency have been developed. From past experience with oil and gas wells, the following trends have emerged: • Sand production increases with increasing production rate or decreasing wellhead pressure. • A sudden change in production rate causes increased sand production. • In some cases, once sand has begun to be produced, sanding becomes uncontrollable. • The tendency to produce sand is enhanced if the reservoir is overpressured. As was discussed previously, sand production can be triggered by either a mechanical failure of the formation or a collapse of the cementing material that adversely reacts to chemicals or fluids pumped into the well. Creating a short, highly conductive fracture can effectively

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Several methods are used to predict the occurrence of sanding. These methods are in-situ mechanical properties, in-situ stresses and failure criteria, logging methods, and field observations.

Early sand prediction techniques2 were based on mechanical properties values and suggested that a threshold for sanding exists at G 0.8 1012 psi 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2.12) cb where G is shear modulus (dynamic), and cb is bulk compressibility (dynamic). Any formations with values that fall below this criterion are believed to require sand-control measures. Another important investigation for sand prediction is the study of the microstructure of the formation and the stress-strain characteristics of these formations. Halliburton’s experience suggests that the sanding threshold has many limitations and that an empirical formula devised for one field does not apply to other areas and lithologies. Extensive laboratory testing of numerous sand-producing formations has led scientists to believe that examining only the mechanical properties of the formation is not enough to predict sand production. Table 2.1 displays Halliburton’s laboratory-measured rock properties for various formations with sanding tendencies. Also displayed are the properties for graded proppant sand and synthetic friable rocks. Normal ranges for some of the properties of consolidated sandstones are also given.3 The samples from Formation A, Formation B, Formation C, and a sample from an outcropping of the Antler Sand formation all exhibit Young’s moduli that are small enough to fall below the G/cb threshold that indicates sanding. By using laboratory-determined and estimated parameters, a G/cb value for formation A was calculated at 0.23 x 1012 psi, well below the cutoff. By looking at the cores taken from Formation D, a deep well that had a sanding history, the Young’s moduli of these consolidated sandstones seem to indicate that G/cb is

Table 2.1 — Comparison of Rock Properties Depth (ft)

E (106 psi)

Co (psi)

l (psi)

20/40

t (psi)

(deg)

0

29.6

131

51*

Gopher St. Sand Formation A

4675

0.27

0.65

1779

210

33** Formation B

6412

Formation C

0.061

0.88

215.8

0.076

0.87

215.8

0.050

0.14

Synthetic

1st load

0.07

(7% cement

2nd load

0.213

3% clay)

3rd load

0.226

Synthetic

1st load

0.037

(5% cement

2nd load

0.13

5% clay)

3rd load

0.048

0.07

87

0.377

0.625

1037.5

Antler Sand

0

165***

192***

41

230***

200***

41* 20**

Formation D

15,814

4.44

0.28

16,550

8.16

0.19

17,047

4.54

0.33

4.24

0.16

17,171 Normal

0.5 to 11.5

Ranges * Initial

2,800 to

500 to 3,600

24,000 ** Final

*** Extrapolated value

Table 2.2 — Young’s Modulus as a Function of Confining (Stress Antler) Sand

cont (106 psi)

E (106 psi)

cont (106 psi)

E (106 psi)

0.377

1,000

0.377

250

0.478

2,000

0.478

500

0.595

4,000

0.595

0

likely to be well above the sanding threshold. Other factors play a major role in the failure of these formations.

Antler Sand sample as a function of confining stress. The increase in modulus yields the following implications:

Another factor that must be considered when using insitu mechanical properties to predict sanding tendency is the fact that the Young’s modulus (and thus the shear modulus) of many friable sands increases as confining stress increases. Table 2.2 shows the modulus for the

• The deeper a formation is, the less likely the formation is to produce sand, based on this method of sanding tendency prediction. • The more that the pressure is drawn down at the wellbore, the more susceptible the sand face becomes to failure.

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FRACPAC COMPLETION SERVICES Stress – Strain of Poorly Consolidated Sandstone

Stress – Strain Confined Sandstone

350

3,500 Young's Modulus = 0.061 x 106 psi Compressive Strength = 215.8 psi

Failure at 7,420 lbs (3,079 psi)

3,000

250

Axial Pressure (psi)

Axial Load (lb)

300

200 150 100 50

2,500 2,000

Et = 0.133 x 106 psi

1,500 1,000

Et = 0.1 x 106 psi

0 0

0.004

0.008 0.012 Displacement (in.)

0.016

500

0.018

Confining Pressure 500 psi

0

Figure 2.7 — Poorly consolidated sandstone shows a nonlinear trend when plotted on a stress-strain curve. This trend is much more pronounced than in harder, consolidated rock. The nonlinearity is believed to be due partly to the limited compressive force that can be applied when testing unconsolidated sands.

0

Et = 0.121 x 106 psi

Et = 0.087 x 106 psi Confining Pressure 500 psi

0

Failure at 7,560 lbs (3,235 psi)

2,500 2,000

Et = 0. 2 x 106 psi

1,500 1,000 Confining Pressure 800 psi

0

.01

.02 .03 Displacement (in.)

.04

.05

Figure 2.8 — When a poorly consolidated sample is confined and compressive force is applied, the resulting stress-strain curve more closely follows a linear trend. The sample is this test was confined with 500 psi of pressure.

Neither of these implications predict how sanding tendency changes with time, nor do various other sanding-prediction techniques. Figure 2.7 shows the stress-strain curve for a poorly consolidated sandstone. The nonlinearity of this curve appears to be more pronounced than in consolidated rocks. Because of lower compressive strengths of poorly consolidated formations, compressive testing of these

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0.07

3,000 Axial Pressure (psi)

Axial Pressure (psi)

3,500

1,500

500

0.06

Stress – Strain Confined Sandstone

Failure detected at 4,540 lbs (1,884 psi)

1,000

0.02 0.03 0.04 0.05 Displacement (in.)

Figure 2.9 — Again, a poorly consolidated sample was confined and subjected to compressive force until it failed. Confining pressure was 500 psi.

Stress – Strain Confined Sandstone 2,000

0.01

500 0 0

0.01

0.02 0.03 Displacement (in.)

0.04

0.05

Figure 2.10 — As the confinement force increases, the stress-strain curve becomes even more linear. The confining pressure was set at 800 psi in this test.

samples must be performed at lower stress levels than those of conventional sandstones. Hence, part of the nonlinearity characteristic is caused by these lower compressive stresses used in testing. At the present time, any possible relationship between nonlinearity and sanding tendency has not been investigated. Nonlinearity also brings into question the use of a single Young’s modulus value when modeling fracture growth

Figure 2.11 — The grain-to-grain structure of Antler Sand in its natural state. Note how closely the grains contact each other.

Figure 2.13 — The shear-failure plane of natural Antler Sand after failing at 5,000 psi, under confined test parameters, shows the radical rearrangement of the grain structure.

Figure 2.12 — Antler Sand was also remolded to be used in tests. The remolded sand somewhat resembles the natural, but the close grain contact is absent.

Figure 2.14 — Remolded Antler Sand also failed at 5,000 psi, under confined conditions. The shear-failure plane is shown. Again, the grain structure is very perturbed.

in unconsolidated formations,4 as well as the use of conventional minifrac techniques. The nonlinearity of unconsolidated formations becomes less pronounced when the sample is tested under confinement as shown in Figure 2.8 through Figure 2.10. For the design of a FracPac treatment, it is important to use an equivalent Young’s modulus for the pressure range to which the formation will be exposed.

production problems during the production phase of the well. A joint research project between Hallilburton and the Rock Mechanics Consortium at the University of Oklahoma is studying the difference between natural poorly consolidated sandstone (from an Antler Sand outcropping) and a remolded sand as a model for this type of formation. Figure 2.11 shows the natural Antler Sand and clearly depicts the grain-to-grain contact structure that is common to this type of formation. Figure 2.12 shows a sample of Antler Sand that has been remolded and displays more loosely structured grain contact. Figure 2.13 and Figure 2.14 show the sand grains of each of these respective formations at their shear planes after the samples failed under confined conditions at 5,000 psi.

The stress-strain relationship describes the way the framework of granular material in the formation responds to the applied load. Also, this relationship reflects whether or not continuum mechanics principles can be applied. The granular framework plays an important role in sand

15


Shear Stress vs. Normal Stress Formation A 8

.30 Shear Stress (kpsi)

Young's Modulus (psi x 106)

Young's Modulus vs. Confining Pressure

.20

.10

0

6 33.3° 50.7°

4

2

0 0

200

400 600 800 Confining Pressure (psi)

1,000

Figure 2.15 — The relationship between Young’s modulus and the confining pressure shows a linear trend.

-1

0

2

4 6 Shear Stress (kpsi)

8

10

Figure 2.17 — Formation A also shows an initial friction angle that is greater than 30°.

Shear Stress vs. Normal Stress Formation B

Shear Stress (kpsi)

3

In-Situ Stresses and Failure Criteria As mentioned earlier in the chapter, Formation D may differ from the other formations in Table 2.1 in the type of mechanism that causes it to fail. The Mohr-Navier failure theory forms the basis of the most currently used methods to predict formation failure and sand production. Other methods have been developed to estimate cohesion and the angle of internal friction, which are parameters needed to develop a MohrCoulomb plot.

2 40.7°

1

0 0


3

Figure 2.16 — Formation B shows an initial friction angle that is greater than 30°. A Mohr’s stress analysis, such as the one shown, can help determine a sandstone’s degree of consolidation. Sanding tendency, however, requires the consideration of several other factors.

Table 2.1 and Figure 2.15 through Figure 2.18 show that poorly consolidated formations, such as those of Formation A, Formation B, and the Antler Sand outcropping, may exhibit an initial friction angle that is greater than 30°. Conclusively, Mohr’s stress analysis, including consideration of cohesiveness and friction angle, can provide a means of determining a sandstone’s degree of consolidation. Figure 2.19 shows a Mohr’s circle analysis of a formation at a static, shut-in condition. If a well is subsequently produced, the change in wellbore pressure causes an increase in the tangential stress and a decrease in equal magnitude of the radial stress. Thus, the center of Mohr’s circle remains stationary, but the radius grows, approaching the failure line as the wellbore pressure decreases. The decrease in the pressure at which the Mohr’s circle intersects the failure line (also shown in Figure 2.19) is

16

the maximum safe drawdown. When the Mohr’s circle touches or crosses the failure envelope, shear failure and sand production can be expected.

Uniaxial Compressive Strength The Mohr-Coulomb failure criteria has been used to predict sanding tendency based on the uniaxial compressive strength concept. 7 1 - p = 2u tan + (3 - p) tan2 . . . . . . . . . . . . . (2.13)

Antler Sand Outcropping 10

8 Shear Stress (kpsi)

Because of the loss of interfacial tension and cohesiveness that can occur with high water cuts, producing a well with a higher water cut may require a higher intrinsic shear strength of the formation than is predicted by other models. A statistical model that extends the Mohr’s circle analysis was developed to predict sanding in wells along the Gulf Coast of the U.S., or in similar wells where free water is being produced. 5 The following failure criteria were developed.6, 7

Shear Stress vs. Normal Stress

6

33.3° 50.7°

4

2

0 0

2

pdraw = 2cu

for radial flow


10

12

Figure 2.18 — The Antler Sand sample shows an initial friction angle that is greater than 30°.

Equation 2.13 shows that at the borehole, the following criterion can follow: pdraw = cu

4

Mohr's Circle at Static Shut-in τ

for spherical flow

where

We have discussed the in-situ properties of the formation and what they can mean in the productive life of a well. Sanding tendency also plays a role in whether the well will remain productive for a long period. If a well is a likely candidate for sanding due to poorly consolidated formation, then measurements must be made to more closely determine the formation properties. These measurements are usually made with well-logging tools and equipment.

Well-Logging Methods Well-logging methods tend to rely heavily on wireline acoustic logs. Although more detailed methods, such as those already discussed, are preferred, a simple rule of thumb based on acoustic travel time through the formation is often used to distinguish between hard (fast) and soft (slow) formations. Velocity is a unit commonly used by geophysicists to measure seismic waves. Subsurface formation compressional velocity ranges from

Flowing at ∆pM

∆pM

pdraw is drawdown and cu is the uniaxial compressive strength of the formation.

Static

σr1

σr

σθ

σθ1

σ

Figure 2.19 — The well shown is at static or shut-in conditions. If the well is later produced, the change in wellbore pressure causes an increase in tangential stress and a decrease in radial stress of equal magnitude. The center of Mohr’s circle remains stationary, but the radius grows. As wellbore pressure decreases, the failure line is approached by Mohr’s circle.

17


6,000 to 25,000 ft/sec. Shear-wave and compressionalwave interval transit time, or slowness (ts and tc , respectively), are measurement units used by acoustic log analysists and petrophysicists. Slowness is simply the time required for the acoustic wave to travel a known distance; on most acoustic tools this distance is 1 ft. Velocity is expressed in ft/sec, whereas slowness is expressed in

sec/ft. The rule of thumb used in the acoustic log analysis practice is that formations with ts greater than 160 sec/ft are generally considered soft or slow formations.8 In sandstone, a ts of 160 s/ft translates to a tc of about 90 sec/ft. The 160- sec/ft definition is convenient, since the characteristics of the acoustic wavetrain change significantly at this time interval; the compressional-wave amplitude increases and the Stoneley wave becomes controlled by shear velocity at approximately 160 sec/ft. The shear wave does not propagate in slow, unconsolidated formations that are generally the focus of FracPac treatments; therefore a special, low-frequency dipole acoustic tool must be run to measure a flexural wave that is propagated in such formations. The flexural wave travels at the same velocity as the shear wave at the frequency that it is transmitted from the tool, so shear-wave slowness is calculated for slow, unconsolidated formations. Logging engineers and analysts, who are familiar with acoustic logs, can look at waveforms being received after traveling through a formation and immediately recognize whether the formation is slow (soft) by its unique waveform signature. The rule of thumb discussed does not guarantee that a well will have sanding problems, but does offer a practical, operational definition for recognizing unconsolidated sands.

Field Observations In the Gulf of Mexico, operators have set guidelines for drawdown control for sand production.9 The drawdown guidelines vary from 500 to 800 psi across the drainage area including the gravel pack. A different method of sand control involves limiting the production rate to 15 bbl/day/perf, assuming that 60% of the perforations are productive, with variable drawdown. FracPac services use special methods to create induced fractures and pack them properly to avoid potential damage to the well by sanding. Tip-screenout fracturing and the behavior of the formation while fracturing are crucial to a successful treatment and are discussed in the following sections.

18

TIP-SCREENOUT FRACTURING The-tip screenout fracturing (TSO) technique applies hydraulic-fracturing technology to create a wide, short fracture that yields high production rates with reduced pressure drop.10 TSO can be a highly effective technique in controlling sand and stimulating maximum production from weak formations. Ideal candidates for hydraulic fracturing with planned screenout include the following types of wells: • Wells that require a limited fracture size or a fracture that just bypasses wellbore damage. These may be wells with no boundaries for fracture-height restriction, wells with a nearby aquifer, injection wells, or slim holes spaced close together in a field. • Formations that are not candidates for matrix acidizing. • Reservoirs with moderate to high permeabilities, with or without formation damage. • Wells that require restricted production rates for sand control (or otherwise need prevention from formation failure). • Wells that have been previously gravel packed and have lost production because of pore collapse and plugging of the gravel pack due to fines migration. TSO fracturing design is discussed in detail in the following sections from a rock mechanics perspective and includes discussion of fracture geometry, fracturing pressure analysis, deviated and horizontal well applications, and perforating design.

Fracture Geometry The design of fracture height, width, length, and conductivity should be determined before the stimulation is performed. The following aspects of fracture geometry are important in making design decisions.

Fracture Height 10

BHTPC Closure (kpsi)

Fracture height should be restricted so that a wide fracture is created, which is a key factor in the success with tip-screenout-fracturing applications. Knowledge of the in-situ stress profile in the payzone and the surrounding boundaries is crucial to sound TSO treatment design. In formations that have no boundaries to the pay zone, a penny fracture usually results. The mechanical properties and the in-situ stress profile can be used to determine the injection rate needed to contain the fracture within the pay zone.

Typical Pressure Response for Fracturing with Planned Screenout

1

Fracture Width Fracture width development of TSO fractures in unconsolidated formations does not follow the analysis conventions of hydraulic fracturing in hard rock. Conventional hydraulic fracturing analysis has a width equation that applies to the linear elastic region of the stress-strain relationship of a given rock. Unconsolidated sands, however, exhibit highly nonlinear behavior when stress is applied to them. When a soft formation is hydraulically fractured, the net treatment pressure in the fracture could be within the stress-dependent Young’s modulus region of the stressstrain relationship. Because this area is small, it can be ignored when analyzing a fracture in conventional rock; however, it should not be neglected when an unconsolidated sand is hydraulically fractured. In sands, there is a zone within a critical distance from the fracture in which deformation is taking place. Beyond this critical zone, the rock does not experience the applied stress. Thus the formation beyond the critical zone near the fracture does not exert any elastic rebound toward the fracture when fluid pressure is released in the fracture. The combined effects of sand compaction and the stress-dependent Young’s modulus result in a wide fracture being created in unconsolidated sands. A general equation was developed that describes the stress-strain relationship of rocks that exhibit nonlinear behavior under load:12 2 E∞n - O tan-1 n . . . . . . . . . . . . . . . . . . . (2.14) O

where E∞ is stress-strain slope approached as stress increases, and O is the negative of the stress-axis intercept of the straight line being approached. Additional parameters which appear in variations of the equation are O is a divisor of the strain, n is an exponent, n is strain (normal), and c is a compressibility.

0 1

10 Time (min)

100

Figure 2.20 — The pressure response for fracturing with a planned screenout shows events during the treatment that are typical such as pressure buildup, fluid leakoff, and screenout.

Fracture Length and Conductivity Fracture length and conductivity for tip-screenout designs of FracPac should be optimized using a reservoir simulator. A reservoir simulator can also be used to predict the maximum pressure-drop region around the wellbore. The fracture length and conductivity can then be designed to effectively bypass the maximum pressure-drop region or the near-wellbore damage region.

Fracturing Pressure Analysis Stimulation treatment pressure is monitored during the job and used to analyze fracture-growth behavior. Plots of pressure versus time at a given injection rate are data that Halliburton obtains from a fracturing treatment, and these plots are carefully analyzed to evaluate a fracturing treatment (Figure 2.20). When a tip screenout occurs, the treatment pressure increases with time if the injection rate is constant. An increase in pressure can also be caused by other mechanisms and should not be confused with the tip screenout during the treatment.

19


Pressure behavior during a minifrac test (run before the fracturing treatment) can provide a valuable reference when analyzing the pressure data acquired from the main fracturing job. A minifrac test must be performed, not only to collect fluid-leakoff data coefficients, but also to be used as a reference for analyzing pressure-versus-time data. Three mechanisms exist that are known to cause a rapid pressure increase with time during a fracturing treatment: near-wellbore or perforation restriction, complex fracture geometry, and screenout mode.

Near-Wellbore Restriction, Perforation Restriction, or Both It is a well-known phenomenon in hydraulic fracturing that the treatment pressure will increase when a nearwellbore restriction or a perforation restriction exists. In some cases, a combination of both of these restrictions is present. It is very important to differentiate a tip screenout from a near-wellbore screenout. Experienced engineers and fracturing practitioners can differentiate between tip screenout and near-wellbore screenout, if they consider all of the available well data to reach a conclusion. However, controversy among fracturing experts exists, which suggests that many screenouts that are considered tip screenouts are actually caused by blockage at or near the perforations.11 It was also suggested that a tip screenout can be controlled with proppant scheduling and fluid rheology, and not by pad volume. Step-up tests, step-down tests, or both can be used to evaluate the nature of the restriction, making it possible to differentiate between perforation restrictions or near-wellbore restrictions. Identifying the nature of restriction can help modify the job design to properly handle specific well conditions.

Fracture Geometry An increasing pressure trend may be caused by fracture geometry such as restricted fracture height, multiple fracture strands, and fractures that have reoriented themselves. The pressure response during a minifrac test can be used to help analyze the data during a fracturing treatment in which the pressure response is suspected of being altered by unusual or complex fracture geometry.

20

Screenout Mode To analyze a pressure response, the traditional Nolte-type screenout mode is used.12 The Nolte-type analysis assumes that if the slope is equal to 1 on a plot of net pressure versus time, a tip screenout has occurred. This pressure response is similar to the storage effect that is caused by fluid compressibility during well testing. To understand this behavior, it is necessary to derive the following equation based on constant liquid compressibility: q dt c V dp

q log plog log t . . . . . . . . . . . . . . . . . . . . . . . (2.15) cV A plot of p versus t on a log-log scale graph should yield a straight line with a slope of 1. The equation above is based on the following conditions: • Injection rate (q) is constant. • Fluid compressibility (c) is constant over a given pressure range (p). • V is the volume of the system, which is assumed to be constant over the time span (t). • The system is saturated with a fluid of constant compressibility (c). Note that ∆p in the equation is defined as the difference between two pressures within the pressurization time span. Formations that exhibit significant nonlinearity violate an implicit assumption in current fracturing-pressure analysis techniques. An example of this violation is the curvature exhibited by a number of unconventional formations. This curvature distorts the slope of the log of net pressure versus the log of injection time or volume plots. Also suggested was that by substituting ∆ or ∆[ (1−v 2)] for pn in the various net-pressure plotting techniques, most valid guidelines continue to be valid for the new plots.4 Nonlinear formations may also exhibit significant hysteresis, which is apparently an effect caused by the same mechanisms as the nonlinearity. Since minifrac analysis is performed during a phase in which the formation is relaxing, the validity of the nonlinearity and the hysteresis effects are questionable. The nonlinearity and hysteresis may help explain the anomalous pressure decline observed in other formations such as coal seams.13

FRACTURING CHARACTERISTICS 400 psi

To understand the behavior of poorly consolidated formations while undergoing fracturing at Halliburton’s Rock Mechanics Laboratory, large-scale samples of Antler Sand were fractured with triaxial stress applied to them. An ongoing research program was initiated to answer the following questions:

400 psi

• Does fracturing poorly consolidated formations follow the conventional theory of creating a singular fracture perpendicular to the minimum horizontal stress? • At what horizontal-stress contrast is the induced fracture not governed by the stress-field directions?

200 psi 300 psi

300 psi

• Is the fracture direction governed by the orientation of the perforations, and if so, what perforation phasing is most effective? • Does the fracture geometry in horizontal and deviated wells drilled in poorly consolidated formations follow the same behavior that is observed in competent formations?

200 psi

Figure 2.21 — The vertical well shown was drilled into a poorly consolidated formation, and a vertical fracture was created. Telltale signs of high fluid leakoff are noticeable.

Figure 2.21 shows a vertical well drilled into a poorly consolidated formation. A vertical fracture was created and propagated. Note that the fluid leakoff was high and very noticeable. Figure 2.22 shows a similar test performed with a different stress field imposed. This research is ongoing and will address other important concerns of fracturing poorly consolidated formations.

1,000 psi

Deviated and Horizontal Well Applications The primary rock mechanics issue of fracturing horizontal and deviated wells in poorly consolidated formations is the fracture geometry at and near the wellbore. Fracture initiation plays a critical role in how the fracture geometry pattern is created near the wellbore. Until fracturing begins, the formation remains in a static situation, or in equilibrium, and a balance of related radial, vertical, and tangential in-situ forces exists around the wellbore. Both theory and experiments indicate that fracture initiation in horizontal and deviated wells does not mimic fracture initiation in vertical wells.14 Unlike conventional wells, and the axial (normal) fractures that occur in them, horizontal-well fractures do not always initiate perpendicular to the minimum horizontal stress. A degree of shear failure, which is not present in fractures of vertical wells, accompanies the initiation and extension

600 psi

500 psi

Figure 2.22 — Another vertical well was drilled into this poorly consolidated formation with a different stress field. The increase in overburden caused the fracture to extend farther horizontally into the formation with less vertical growth.

21


of almost all fractures in wells that deviate from vertical or are horizontal. Single or multiple fractures are common within these wells, and the fracture behavior is dependent on wellbore orientation versus the in-situ stresses of the formation that it traverses.

1,400 psi

3,000 psi

Single Fractures

si

2,500 p

2,500 p

si

Figure 2.23 — The fracture in this test initiated in a longitudinal orientation. The wellbore was drilled in the direction of maximum horizontal stress, causing the fracture to propagate perpendicular to the minimum horizontal stress. This alignment with the borehole seems to be optimum, since the fracture initiated immediately behind the casing.

Results from experiments at Halliburton reveal a tendency of single, planar fractures to form in horizontal wells drilled in the direction of one of the principal horizontal stresses.15 Figure 2.23 shows such a fracture that initiated longitudinally, i.e., aligned with the borehole. This experimental wellbore was drilled in the direction of the maximum horizontal stress, causing the fracture to initiate perpendicular to the minimum horizontal stress. This orientation seems to be optimum, since the induced fracture initiates in alignment with the borehole, immediately behind the casing. There exists some tolerance in the wellbore azimuth, which allows the borehole to vary as much as 10° from the true perpendicular to the minimum horizontal stress and still promote good fracture initiation. Single, planar fractures are by far the most preferred geometry, since any other type of fractures caused by improper borehole direction require higher initiation pressures and create complicated fluid flow paths into the wellbore.

1,400 psi

Multiple Fractures Near the Wellbore

2,500 psi

2,500 psi

3,000 psi 1,400 psi

Figure 2.24 — Multiple fractures that form in horizontal or inclined wells generally have openings that are smaller than those created by a single, planar fracture. Such narrow openings can create high treatment pressures and can trigger early screenout.

22

The direction of the wellbore and the angle that it intersects the principal horizontal stresses can cause multiple fracture geometries to be formed. Multiple fracture systems are very erratic in the way they form and present complex fluid flow problems that hinder a successful stimulation treatment. Multiple fractures, such as those shown in Figure 2.24, that form in inclined or horizontal wells have openings to the wellbore that are generally smaller in width than the opening created by single, planar fractures. Such narrow openings can cause high treatment pressures and can trigger early screenout. Early screenout occurs when proppant jams in a narrow passage or bend before it reaches the leading tip of the fracture. An unpropped section of the fracture is left from the tip to the bridging point. Therefore, narrow openings of multiple-fracture systems near the wellbore are not desirable, and any practices that cause this should be avoided whenever possible. Special design considerations must be applied in cases where these conditions cannot be avoided.

Perforation Design Perforations play a critical role in achieving a successful fracturing treatment performed in vertical and horizontal wells. Perforations, and ultimately fracture initiation, determine the communication path between the wellbore and the fracture plane that extends from the wellbore into the formation. Good perforation design and implementation can help prevent nonplanar fracture geometries such as multiple strands, reorientations, T-shapes, and other complex systems from forming. Serious impedence in the form of narrow multiple fractures, high fluid leakoff, and increased friction pressure in the fracture can result from nonplanar fracture geometries forming. To minimize these potential problems and their effect on a successful fracturing stimulation, a perforation design should be in phase with the anticipated fracture direction to help ensure that the following events occur: • A fracture propagates perpendicular to the minimum horizontal stress, which gives a maximum fracture width. • A single fracture propagates. • Fracture initiation and extension pressures are reduced, which is desirable in any fracturing treatment. Fortunately, this aligned perforation orientation is in agreement with treatment methods that best inhibit sand production. Aligned perforations also offer the advantage of establishing the most stable perforation tunnels possible since they are oriented in the direction of maximum horizontal stress and the anticipated direction of an induced hydraulic fracture. For a horizontal well, perforations should be oriented at the upper and lower sides of the wellbore and possibly oriented in the direction of the anticipated fracture as shown in Figure 2.25. For poorly consolidated formations, the magnitudes of the horizontal stresses may be approximately equal in value. This suggests that an induced hydraulic fracture is directed by perforation orientation rather than in-situ stress orientation. A 180° perforation phasing should be considered in unconsolidated formations with a stress field of this nature. When a wellbore penetrates a competent formation, a stress concentration field will be created around it. If this stress field magnitude surpasses the formation strength, failure occurs and can initiate sand production, which can progress throughout the reservoir. To eliminate stress concentrations, ideally a wellbore or perforation tunnel

σv

Single Fracture

Single Fracture

f

• Single • T-shaped • Multiple σHmin

σHmax

• Multiple (at wellbore) • Reorientation • Reorientation • Multiple Fracture (away from wellbore)

Figure 2.25 — In horizontal wells, the perforations should be oriented at the upper and lower sides of the wellbore, and in the direction of the anticipated fracture, if possible. Characteristic fracture geometries for other wellbore orientations are also shown.

should not be introduced into a formation. If possible, another method to deplete the reservoir should be used. If sand production is a major concern for a poorly consolidated formation that is to be treated, an innovative technique may be used for sand control. This technique is not reliant on a circular borehole being introduced to the formation. However, the hydrocarbonbearing formation is accessed by a hydraulic fracture that extends from a remote wellbore. This method is used primarily with horizontal wellbores, but it is also effective when used in vertical wells.

Vertical Wells For maximum sand control, the vertical well can be drilled very close to, but not into, the unconsolidated sand interval. A 1- to 5-ft interval is then perforated into a formation layer that bounds the pay zone, and a carefully designed fracture is created.

23


Horizontal Wells In horizontal wells, where maximum sand control is desired, the following technique can be used to avoid drilling or perforating into an unconsolidated sand: 1. A horizontal borehole is drilled into a boundary formation adjacent to the poorly consolidated sand reservoir. 2. Oriented perforating is performed with zero phasing; i.e., the charges are aimed toward the lower side of the horizontal well. 3. A hydrofracture is initiated, which should be designed as a tip-screenout treatment. Resin-coated proppant is used throughout the entire job. The previously mentioned techniques to control sand production are based on the following observations and concerns: • When compared to a vertical well, the horizontal well reduces the drawdown for a given production rate. The drawdown places increased deviatory stress on the formation, which can cause formation failure and ensuing sand production if the increased stress exceeds the formation strength. • Creating a conductive fracture transforms the radial flow into linear flow before reaching the wellbore and thus reduces the fluid convergence that is present with radial flow. Ultimately, the drawdown is decreased for a given production rate. • Formation failure begins near the wellbore due to the stress concentration created after a wellbore is drilled into the formation. The aforementioned drilling technique is an innovative, indirect method of fracturing into the producing zone that avoids penetrating a structurally weak formation and inducing stresses that can cause failure and sand production. In addition to using oriented perforations to control sand production, oriented hydrajetting can help create a single, continuous initiation path for fracturing. In unconsolidated formations, a prefracturing sand-consolidation stage can be pumped to help initiate a single fracture, rather than ballooning a cavity into the formation.

MEASURING IN-SITU STRESSES As discussed previously, the in-situ stresses and mechanical properties of the formation are crucial in evaluating sanding tendency and in the design of a FracPac treatment

24

for oil and gas wells. Several methods are available to measure the magnitude and direction of the in-situ stresses in the formation. The primary methods used are microfrac testing, extensometer measurement, and anelastic strain recovery. Other methods of measuring in-situ stresses involve the measurement of borehole breakout, the Kaiser effect, downhole imaging tools, and acoustic logging tools.

Microfrac Testing Microfrac testing procedures are true to their namesake in that they create a very small (micro) fracture at the desired depth within a well.16, 17 This procedure is performed by injecting a small volume, typically 1 to 2 bbl, of fracturing fluid into a limited area of the wellbore that is isolated between a packer and the bottom of a vertical section of the well. The packed-off area is then fractured by injecting fracturing fluid at a pressure that is sufficient to fracture the well. The magnitude of the minimum horizontal stress is determined by pressure fall-off after fluid injection has stopped. An oriented core from the bottom of the well is retrieved, studied, and retained. The core may be used for Anelastic Strain Recovery (ASR) tests. Measurements of the microfrac core generally yield stress directions, with the direction of minimum horizontal stress being perpendicular to the direction of the induced fracture. Microfrac procedures can be performed in either cased hole or open hole, with open hole being the preferred method, since it is possible to recover a fractured core sample.

Microfrac-THE Tool Test Microfrac testing can be performed in combination with the Total-Halliburton Extensometer (THE) tool, which is a high-precision, multi-arm caliper. This tool is coupled with orientation-, pressure-, and temperature-measuring devices. Also, straddle packers are part of this tool and enable it to isolate individual zones and test them. During the test, the deformation of the wellbore is measured. Deformation readings are taken before, during, and after hydraulic fracture initiation and propagation. These data are analyzed to obtain the in-situ stress field, determine formation mechanical properties, and measure fractureclosure pressure and fracture width.18, 19

Anelastic Strain Recovery

Wireline Testing

The ASR testing method is used to predict the direction of the in-situ stresses in the formation. This method is based on the theory that a core relaxes when the in-situ stresses are removed from it.20 The amount of relaxation is related to time and is directly related to the magnitude and direction of the downhole stresses that were imposed on the core. To perform the ASR procedure, an oriented core must be available. An instrument capable of measuring displacements with a resolution of less than one microstrain is used for ASR testing.

Directional acoustic measuring devices, such as the circumferential acoustic scanning tool (CAST) and the borehole televiewer (BHTV), can be run on wireline to observe natural and induced fractures that intersect the borehole wall.6, 7 These tools are deployed on a wireline, and both have high-frequency transmitter/receiver heads that rotate about the axis of the tool. As the head rotates, it transmits sound waves that travel to the borehole wall, reflect, and return to the receivers on the rotating head. Reflections off smooth areas of the wellbore wall appear as light-colored areas in the resulting image, whereas fractures and rough areas appear as dark-colored areas. The orientation of the rotating transmitter/receiver head can be related to azimuth at any instant thus yielding directional fracture information.

The ASR method is very reliant on time and rock properties. A stabilization time is reached, at which relaxation can no longer be measured, so the procedure is usually performed at the wellsite. ASR testing can be performed on core specimens from vertical or inclined wells.

Other Testing Various techniques are used to directly and indirectly measure the in-situ stress field around the proposed borehole. Data from regional geological surveys may be consulted, or borehole breakout data may be studied. Borehole breakout is measured with an X-Y caliper tool. The borehole tends to break out, or become elliptical, in the direction parallel to the minimum horizontal stress.21, 22

Stress magnitude in competent formations may be estimated by running a long-spaced sonic logging tool in the vertical section of the well. From sonic measurements, logs can be produced that display a combination of formation bulk density and an estimate of Poisson’s ratio and that are useful in indirectly calculating the stress values in the formation. These logs can be calibrated from microfrac data obtained in one or more intervals and used to estimate the minimum horizontal stress in another interval where microfrac was not run.

The Kaiser Effect A sustained interest in the Kaiser effect for geomaterials has existed for quite some time.23 The Kaiser effect involves the emission of miniscule acoustic signals by core grains when a stress is applied to the core. The effect forms the basis of a method for determining the stress within a core sample. In the test, the core is subjected to a sequence of stresses. During the first cycle of loading, a high-frequency sound burst is emitted. In subsequent cycles, however, there is an absence of these emissions until the previous maximum stress is surpassed. A marked increase in emission then begins. This increase has been termed the Kaiser peak, or Kaiser step, and is believed to hold a stress history of the material being tested. By using this technique to test geomaterials, the first cycle of uniaxial loading could yield the in-situ stress level that once was placed on the core. This method of testing determines stress directly rather than measuring strain and deducing stress from it.

25


NOMENCLATURE = Angle of friction (degrees)

Fsoft = factor, softening

= stress, shear (psi)

G = modulus, shear (dynamic)

= stress, effective (psi)

k = permeability, reservoir (md)

= Biot’s constant

kf bf = conductivity, fracture (md-ft)

O = negative of stress-axis intercept

Lf = half-length, fracture (ft)

= stress, tangent, effective (psi)

p = pressure, reservoir

= stress, tangent, effective 0 = divisor of strain coh = strength, cohesive, or cohesion

pdraw = pressure, drawdown (psi) pp = pressure, formation pore (psi) pwf = pressure, bottomhole, flowing

H = stress, horizontal, maximum (psi)

q = injection rate

h = stress, horizontal, minimum (psi)

r = radius (ft)

n = stress, normal (psi)

rw = radius, wellbore (ft)

n = strain, normal

V = volume

p = pressure drop or differential pu = pressure differential at the wellbore rr = stress, radical, effective (psi) t = strength, formation tensile T = stress, total (psi) t = time span or time differential tc = slowness, acoustic, formation compressional ts = slowness, acoustic, formation shear u = stress, uniaxial (psi) v = stress, vertical, or overburden (psi) C = compressibility, fluid Cb = compressibility, bulk (dynamic) Cf D = conductivity, fracture, dimensionless Cu = strength, uniaxial, compressive (psi)

26

E∞ = slope, stress-strain

REFERENCES 1. Abass, H.H., et al.: “Stimulating Weak Formations Using New Hydraulic Fracturing and Sand Control Approaches,” Paper SPE 25494, SPE Production Operations Symposium, Oklahoma City, Oklahoma, March 21-23, 1993. 2. Tixier, M.P., Loveless, G.W., and Anderson, R.A.: “Estimation of Formation Strength From the Mechanical Properties Log,” JPT (March 1975) 283-293. 3. Stimulation Design, Halliburton Services (1989), Section 6, 8-9. 4. Poulsen, D.K.. and Abass, H.H.: “Hydraulic Fracture Modeling in Formations Exhibiting Stress- Dependent Mechanical Properties,” Paper SPE 26599, SPE Annual Technical Conference and Exhibition, Houston, Texas, October 3-6, 1993. 5. Ghalambor, A., et al.: “Predicting Sand Production in U.S. Gulf Coast Gas Wells Producing Free Water, “ JPT (December 1989) 1336-43. 6. Jeager. J.C., and Cook, N.G.W.: “Fundamentals of Rock Mechanics,” Chapman and Hall Ltd. 11 New Fettar Lane, London EC4P 4EE, 1971. 7. Rinses, R., Bratli, R.K., and Horsrud, P.: “Sand Stresses Around a Wellbore,” SPEJ (December 1982) 883-898. 8. Sharbak, David: personal communication, 1993. 9. Fahel, R.A., and Brienen, J.: “How Gulf of Mexico Operators Design and Perform Sand Control,” World Oil (September 1993) 105-109.

17. Kuhlman, R.D.: “MicroFrac Tests Optimize Frac Jobs,” Oil & Gas J. (January 22, 1990) 45- 49. 18. Kuhlman, R.D., Heemstra, T.R., Ray, T.G., Lin, P., and Charlez, P.A.: “Field Tests of Downhole Extensometer Used to Obtain Formation In-Situ Stress Data,” Paper SPE 25905, SPE Joint Rocky Mountain Regional /Low-Permeability Reservoir Symposium, Denver, Colorado, April 26-28, 1993. 19. Lin, P., and Ray, T.G.: “A New Method to Determine In-Situ Stress Directions and In-Situ Formation Rock Properties During a Microfrac Test,” Paper SPE 26600, SPE Annual Technical Conference and Exhibition, Houston, Texas, October 3-6, 1993. 20. El Rabaa, A.W.M. and Meadows, D.L.: “Laboratory and Field Applications of the Strain Relaxation Method,” Paper SPE 15072, SPE Regional Meeting, Oakland, California, April 2-4, 1986. 21. Miller, W.K. II, Peterson, R.E., Stevens, J.E., Lackey, C.B., and Harrison, C.W.: “In-Situ Stress Profiling and Prediction of Hydraulic Fracture Azimuth for the Canyon Sands Formation, Sonora and Sawyer Fields, Sutton County, Texas,” Paper SPE 21848, SPE Regional Meeting and Low-Permeabilities Seminar, Denver, Colorado, April 15-17, 1991. 22. Yale, D.P., Strubhar, M.K., and El Rabaa, A.W.: “Determination of Hydraulic Fracture Direction, San Juan Basin, New Mexico,” Paper SPE 25466, SPE Production Operations Symposium, Oklahoma City, Oklahoma, March 21-23, 1993. 23. Holcomb, D.J.: “General Theory of the Kaiser Effect,” International Journal of Rock Mechanics and Mineral Sciences, (special issue, February 21, 1993) 1-2.

10. Smith, M.B.: “Stimulation Design for Short, Precise Hydraulic Fractures,” SPEJ (June 1985) 371- 379. 11. Barree, R.D.: “A New Look at Fracture Tip Screenout Behavior,” Paper SPE 18955, SPE Joint Rocky Mountain Regional Low-Permeability Reservoir Symposium, Denver, Colorado, March 6-8, 1989. 12. Nolte, K.G., and Smith, M.P.: “Interpretation of Fracturing Pressures,” Paper SPE 8297, SPE Annual Technical Conference, Las Vegas, Nevada, September 23-26, 1979. 13. Soliman, M.Y., Kuhlman, R.D., and Poulsen, D.K.: “Minifrac Analysis for Heterogeneous Reservoirs,” Paper CIM/SPE 90-5, CIM/SPE International Technical Meeting, Calgary, Alberta, Canada, June 10-13, 1990. 14. Daneshy, A.A.: “The Study of Inclined Hydraulic Fractures,” SPEJ (April 1973) 61-68. 15. Abass, H.H., Hedayati, S., and Meadows, D.L.: “Nonplanar Fracture Propagation from a Horizontal Well-Experimental Study,” SPE 24823, SPE Technical Conference and Exhibition, Washington, D.C., October 4-7, 1992. 16. Daneshy, A.A., Chisolm, P.T., Glusher, G.L., and Magee, D.A.: “In-Situ Stress Measurements During Drilling,” JPT (August 1986) 891-898.

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28

Chapter 3 INTRODUCTION Several gravel-packing techniques are available and are very effective. Each of these techniques has special advantages and is designed for unique applications. This chapter discusses how the gravelpacking process is applied and the many techniques that are available to meet various sand control needs.

THE GRAVEL-PACKING PROCESS Cased hole gravel packing has evolved into a two-stage process. The evolution to two processes was driven by the realization that gravel packs must achieve and sustain high productivity for a well with sanding tendencies. To accomplish these productivity goals, both the perforations and the area external to the wellbore must be packed with sized gravel in a way that provides fluid communication from the undamaged formation to the wellbore. Also, the gravel pack must provide effective sand control by physically supporting the formation and by blocking produced formation sand from reaching the wellbore. A complete pack that is free of voids is one of the most effective sand control measures available to operators. The annular portion (area between the gravel-pack screen and the casing) of the pack alone cannot sustain high-rate well productivity over a long period. The external gravel pack (the area either in a perforation tunnel or fracture that extends past any near-wellbore damage) is a key to prolonged trouble-free production, but cannot, by itself, provide sand control. It is obvious that both the internal (annular) gravel pack

and the external gravel pack should be designed and placed correctly and should work in combination to provide high productivity from the well throughout the economic life of the reservoir.

Sand Control Methods

Perforation Packing Since the quality of the external gravel pack and the packed perforations is critical to high well productivity, efforts to improve this area of gravel packing have been extensive. Fluid leakoff is a key element to successful perforation packing and sand transport to the external pack. Unless the carrier fluid flows through the perforations and into the formation, gravel cannot be transported and packed into the perforation tunnels and subsequently into the fractures, if a fracture stimulation is being performed. The packed perforation tunnels and fractures are the vital link from an area of undamaged formation permeability to the wellbore. Several methods have been developed to enhance fluid leakoff to the formation, thus improving external gravel pack placement. Improvements to sand slurry flow, either with fracture stimulation or without stimulation, have been devised. These improved techniques can be performed with the gravel pack screen and other downhole equipment in place or before the screen is placed across the perforated interval. The preferred packing methods, based on frequency of use, are either prepacking or placing the external pack with screens in place, combined with some form of stimulation such as fracturing or acidizing.

29


Fluid Loss Control One successful method to improve external gravel packing consists of spotting a sand slurry into the open perforations immediately following underbalanced tubing-conveyed perforating. A volume of sand slurry sized to fill the perforations and the casing interval at the perforations and some excess are pumped before retrieving the TCP guns from the well. Sand-control measures are enhanced by packing the sand into clean perforation tunnels. Also, fluid loss control is established by packing the casing ID with gravel. Later, when the gravel is washed from the casing to allow screen placement, lost circulation material (LCM) can be placed above the gravel-filled perforated interval. LCM placed against the outside of perforation tunnels makes cleanup much easier. Removal of LCM can be difficult if it is a combination of particulates (solids) and polymers; failure to remove such solids before the external gravel pack is placed can consume space that is needed for highly permeable gravel. LCM that is free of solids and contains breaker systems can control fluid loss without filling the perforations and the area external to the casing with unwanted solids. These solids deter the formation of an effective gravel pack. Solids-free LCM has been used successfully in many areas including the North Sea. Care must be taken during the washout portion of the procedure to maintain overbalance conditions to minimize removal of the nearwellbore packing already placed in the perforation tunnels. Disturbance of the gravel pack near the wellbore can have detrimental effects on productivity. Fluid losses caused by the washdown procedure and high LCM loss during circulation of the well are disadvantages of this method, as is the significant amount of rig time required to perform this procedure.

Perforation Packing With Acid-Prepack Method The acid-prepack method is a combination stimulation and sand-control procedure that helps yield high productivities from wells that require sand control. Acidprepack is often the method of choice for external gravel pack placement and has proven to be a productive, reliable, and cost-effective treatment in wells all over the world. Operators in Malaysia, the Gulf of Mexico, and China rely on the acid-prepack method to provide the high production rates so critical to the economic success of wells in those regions.

30

The acid-prepack method combines the stimulation benefits of a hydrofluoric (HF) acidizing treatment with the sand-control benefits of packing the perforations and the region external to the wellbore. Alternating stages of acid and gravel slurry are pumped during the treatment. The acid dissolves the damage that is left in the formation from drilling fluids, perforating, completion fluids, and LCM. Of the types of damage that are removed from the perforations and formation, removal of LCM from the perforations is most critical. The perforations should be cleaned with HF and then packed with gravel to ensure that the external pack is connected to the internal pack. If the perforations are not cleaned and then packed with pack sand, formation sand can flow into the perforation tunnels when the gravel pack stabilizes during initial production. One of the most beneficial aspects of the acid-prepack method of sand control is the combination of damage removal or breakdown by the acid and the excellent sand control initiated by the external gravel pack. With damage removed from the formation face, the perforations readily accept carrier fluids that quickly leak off and allow the gravel to pack in the perforation tunnels. This acid and slurry process is repeated several times. As the perforations fill with gravel and the formation is penetrated by the gelled gravel pack fluids, the viscous gel causes flow resistance in the formation pores. This resistance diverts the subsequent stages of acid to other untreated areas of the same perforation, or other perforations, and more uniformly stimulates the entire interval of interest. Damage removal and perforation packing are then evenly distributed over the entire interval, rather than being confined to the first area penetrated by the acid. With the damage removed from the perforations and formation, the well is made more productive and exhibits lower pressure drop across the producing zone for a longer period of time in the well’s producing life. Halliburton has recently developed a crosslinkable HEC gel that works particularly well with acid-prepack treatments. The gel’s crosslinking is broken when it contacts low-pH fluids such as acid, allowing a high degree of fluid leakoff and thus a better external pack. While fluidloss control of the crosslinked gel is excellent, the fluid leakoff rate of the newly developed gel, once crosslinking is broken, equals that of a sheared and filtered hydroxyethyl cellulose (HEC) fluid. Combining the new linear gel with the acid-prepack treatment yields higher productivity with a high degree of sand control, because perforations are first opened and cleaned of LCM, allowing for a better gravel pack.

Cased Hole Screen/Annulus Gravel-Pack Systems Various types of gravel packing systems that provide screened sections of the completion-equipment string for gravel retention and fluid entry are available. The gravelpack medium is delivered downhole in many different ways to provide compatibility with the formation type being treated. The following discussion focuses on the many gravel-packing systems available and their application to unique well situations.

Gravel-Pack Research Gravel-pack studies were performed by Halliburton in cooperation with Clausthal University in northern Germany. The model used for tests simulated Berlin gas storage wells that were to be gravel packed. The model was 39 feet long and was cased with 8-5/8-inch plexiglass. Inside the casing, a 3-1/2-inch gravel-pack screen was positioned. Simulations were based on three different permeability profiles: • 1000-md top zone, 400-md middle zone, and 200-md bottom zone • 400-md top zone, 1000-md middle zone, and 200-md bottom zone • 200-md top zone, 400-md middle zone, and 1000-md bottom zone Conclusions showed water alone as a carrier fluid with 1- to 2-lb/gal sand concentration gave unsatisfactory test results. Best results were obtained by using a 20-lb/Mgal gel with 1-lb/gal sand concentration. This was followed by pumping a stage of brine to help flush any sand buildups in the annulus and prevent premature bridging. The slurry and brine stages were alternated. Halliburton recommends that each sand control completion have a careful analysis done, based on the unique characteristics of the well. Only then can a packing procedure, stimulation procedure, or a combination of these be performed with a high degree of confidence and success.

Slurry Packs Slurry packs carry sand concentrations downhole, into the perforations and into fractures, if a stimulation is being performed. Viscous gel carrier fluids are used to transport sand concentrations of 4 to 15 lb/gal. The main advantages

to this type of system are that a minimum amount of water is used to pump the slurry and the pumping rate can be slowed so that pack sand and formation sand intermixing is minimal. Disadvantages with slurry packs can include voids that form in the annulus pack and incomplete perforation packing, which are caused by the low leakoff rates and the sparing amounts of water used in this system.

Water Packs The water-pack system uses water as a carrier fluid for gravel-pack sand. In recent years, water packs have become a popular alternative to gravel-packing methods that use polymers that can possibly damage formation permeability. Water packs can also help form very tightly packed annular packs. One disadvantage of water packs is their high leakoff rate in high-permeability zones, which can cause bridging in the screen/casing annulus. Bridging in the screen/casing annulus can cause a premature screenout of the treatment. Annular fluid velocity is the key to success with water packing. The returns should have a minimum flow rate of 1 to 2 bbl/min. Flow rates lower than 1 to 2 bbl/min cannot wash sand-node buildup from the annulus.

High-Rate Water Packs High-rate water packs were developed to overcome the high leakoff problems encountered with standard water packs in high-permeability formations. The more effective high-rate water packs are usually preceded by an acid prepack. Also, far more sand (up to 700 lb/ft of perforations) is placed by the more successful high-rate water packs since the formation parting pressure is exceeded. Other successful high-rate water pack treatments have been reported from geopressured reservoirs where very little differential between static formation pressure and formation parting pressure have existed. Although the water pack name indicates that only water is used for proppant transport, frequently a lightly gelled slurry (25-lb HEC/Mgal) is pumped. The danger that zonal isolation may be compromised exists with high-rate water packs, just as it does with FracPac Completion Services. Tracer log data from some wells that have been waterpacked indicate that incomplete entry of the tracer over the entire interval height has occurred, packing only the high-permeability area of the desired zone. Therefore, only wells with sands that are sufficient to resist fracture height growth are candidates for high-rate water packing.

31


Proppant sizes equivalent to those used in gravel packing are generally the best selection for high-rate water packs whereas proppant sizing for FracPac treatments emphasizes fracture conductivity. Pumping rate is determined based on the length of the zone to be packed. The returns rate is restricted so that all but 2 bbl/min are forced into the perforations. A minimum leakoff rate of 5 bbl/min is recommended, even on short intervals, to ensure that the fluid has enough velocity to part the formation and transport the proppant efficiently.

Recommended Improvements to Gravel Packing Procedures Several changes in the way that Halliburton prepares to pump a gravel-pack treatment have helped attain the desired results on client wells in the last 2 to 3 years. These improvements are as follows: • A more thorough cleaning of the casing was performed before filtering fluids. The use of scouring pills and surfactant flushes with suspension aids were added to the wellbore cleanup sequence to remove drilling mud and rust from the tubulars. • A more thorough pickling job was performed, including the use of acid, gel, and a Halliburton pipe-dope removal chemical. The dope-removal chemical should be tested with the specific dope used on the job to ensure that it is compatible. • The use of Flo-Pac is preferred over HEC fluids. Flo-Pac provides good sand suspension, built-in viscosity breaking, high leakoff, and low damage to the formation. Slightly viscosified fluid (25-lb/Mgal) is preferred over the use of water for pumping the annular portions of gravel packs.

32

Chapter 4 INTRODUCTION With the FracPac service, Halliburton hydraulically fractures highly permeable (>10 md) formations to improve production and provide better sand control. While the reservoir engineering aspects of fracturing low-permeability formations have been widely documented throughout petroleum literature,1 these aspects have not been extensively studied for high-permeability situations.

concentrates on two topics: production improvement and sand control. The effects of permeability, wellbore damage, fracture length, fracture conductivity, and fracture damage are studied. Finally, conclusions are presented that can serve as specific guidelines for optimizing FracPac treatments.

Hydraulic fracturing is usually considered as a technique for increasing productivity or establishing production in lowpermeability formations. However, highly permeable formations that have formation damage or sand production tendencies can also benefit from fracturing. For example, a well that has reduced permeability in a damaged zone extending several feet from the wellbore can be made more productive by fracturing through this damaged zone to contact undamaged reservoir. The fracture provides reservoir fluids with a highly permeable pathway from the undamaged reservoir to the wellbore. The conductivity within the fracture can be maximized so that the pressure drop along the fracture itself can be kept to a minimum. In the case of a well with sand production tendencies, a hydraulic fracture decreases the pressure drop necessary to produce the well at a given rate and changes the flow regime around the well such that sand production is minimized or eliminated. Thus, the fractured well can be produced at a rate higher than the unfractured well’s critical sand production rate.

Numerical simulators can be used to gain a better understanding of the effects of various reservoir and fracture parameters on well performance. Simulators allow the effects of reservoir permeability, wellbore damage, fracture length, fracture conductivity, and fracture damage to be investigated quickly and thoroughly. The results discussed in this chapter were generated with a single-phase, 3-D numerical simulator, RTZ.2 RTZ is a finite difference model incorporating a cylindrical coordinate system. It was chosen for its ability to model a radially composite reservoir containing a vertical fracture. The damaged zone was modeled by an inner circular region of reduced permeability extending some radial distance from the wellbore. Outside the inner region was an undamaged region having native reservoir permeability. A fracture was extended from the wellbore to various distances in both the damaged and undamaged zones. In an actual well, damage (reduced permeability) can extend from several inches to several feet away from the wellbore.3 Two general types of data were generated from the simulation runs: productivity as a function of time, and pressure as a function of distance from the wellbore.

This chapter details the reservoir engineering aspects of fracturing highpermeability formations. Specifically, it

Reservoir Engineering

THE STUDY

33


Table 4.1 — Values Applied in Simulations Value

Parameter Initial reservoir pressure, pi

4,000 psi

Effective porosity, e

23%

External radius of wellbore damage, rs

1 and 10 ft

Wellbore radius, rw

0.35 ft

Fracture width, bf

0.5 inches

Total compressibility, c t

25x106 psi-1

Formation compressibility, c f

3x106 psi-1

Fluid viscosity,

1.0 cp

Formation thickness, h

30 ft

Oil formation volume factor, Bo

1.2 RB/STB

External radius of formation, re

1,500 ft (160-acre spacing)

Bottomhole flowing pressure, pwf

2,500 psia (for productivity study)

Surface production rate, q

200, 500, and 800 STB/D (for pressure profile)

Formation permeability, k

0.1, 1.0, 10, 100, 1,000, and 10,000 md

Permeability of wellbore-damaged region, ks Skin, or wellbore damage, S Fracture half-length, Lf Fracture conductivity, kf bf

0.01k, 0.05k, 0.1k, 0.2k, and 0.3k md 0, 4.2, 8, 13.5, 20, 30, 65, 104, and 330 5, 14, 40, 80, and 150 ft 100, 500, 2,000, 4,000, 8,000, and 20,000 md-ft

Distance fracture damage extends into formation from fracture face, bfs Permeability of fracture-damaged region, kfs

1 ft

0.001k, 0.005k, 0.01k, 0.05k, 0.1k, 0.2k, and 0.3k md

Note: Base values held constant during sensitivity analysis of other variables appear in boldface.

34

Productivity as a function of time is best represented in two ways: the first is as cumulative production as a function of producing time; the second is as production increase as a function of producing time. Production increase was calculated by dividing cumulative production for stimulated conditions by cumulative production for unstimulated conditions. The productivity data were generated under the assumption that the well was produced at a constant bottomhole flowing pressure.

Table 4.1 presents the reservoir, fluid, and fracture parameters used in the study. The values of these parameters were chosen to provide a representative example of a typical well that exhibits the effect of each parameter studied. Skin factor, S, was calculated using Hawkins’ Equation4 with the permeability, ks , and outer radius, rs , of the wellbore-damaged region.

Pressure as a function of distance is best represented by a pressure profile along a vertical plane in the reservoir as a function of distance from the wellbore. The pressure data were generated under the assumption that the well was operated under constant rate conditions.

In many wells, production can be improved by a variety of methods, the most common of which are hydraulic fracturing and acidizing. In low-permeability formations, hydraulic fracturing can create a more favorable flow pattern to the wellbore. In effect, the wellbore is extended along the length of the fracture to allow greater productivity. In high-permeability formations, fracturing is used

Production Improvement

Cumulative Production Different Amounts of Wellbore Damage

Production Increase Due to Fracturing 106 k= k=

10

Cumulative Production (STB)

Npstimultated /Npunstimultated

100 S=0 0.1 md 1.0 md

k=1

0 md

k = 100 m d k = 1,000 md

1

k = 10,000 md

No Damage, S = 0 rs = 1 ft, ks = 0.20 * k, S = 4.2 rs = 10 ft, ks = 0.20 * k, S = 13.5 rs = 1 ft, ks = 0.05 * k, S = 20

105

104 rs = 10 ft, ks = 0.05 * k, S = 65 rs = 1 ft, ks = 0.01 * k, S = 104 rs = 10 ft, ks = 0.01 * k, S = 330

103 0.01 Note:

0.1

1.0 10 Time (months)

100

k = 100 md

0.01

0.1


100

All curves indicate the resulting production increase when a fracture with Lf = 150 ft and kfbf = 8,000 md-ft is applied.

Figure 4.1 — Production increases due to fracturing are higher in low-permeability formations than in highpermeability formations.

Figure 4.2 — As wellbore damage increases, cumulative production decreases.

Production Increase Due to Removal of Damage

Effects of Permeability and Wellbore Damage Figure 4.1 shows the expected production increase when a 150-ft fracture with 8,000-md-ft conductivity is applied in undamaged reservoirs having the referenced formation permeabilities. The figure shows that production increase is significant at low permeability; however, as permeability increases, production increase diminishes. Attempts to increase production by fracturing undamaged formations with high permeability (i.e., k > 1 darcy) appear to be futile. Fracturing has little effect on the conductivity of undamaged, highly permeable formations, so production increase is insignificant when such formations are fractured. When damaged, highly permeable formations are fractured, results are different. Figures 4.2, 4.3, and 4.4 show the expected cumulative production and production increase for a 100-md formation with different amounts of wellbore damage. Each figure shows that production increase is significant when the effect of damage near the well, also known as skin, is eliminated. In Figure 4.3, the damaged zone is removed (e.g., by acidizing) and is replaced with

100 rs = 10 ft, ks = 0.01 * k, S = 330

Npundamaged /Npdamaged

to eliminate the effect of damage near the well. This is accomplished by extending the fracture through the damaged zone to contact the undamaged reservoir. This fracture provides a highly conductive path for reservoir fluids to reach the wellbore.

k = 100 md

rs = 1 ft, k s = 0.01 * k, S = 104 rs = 10 ft, k s = 0.05 * k, S = 65

10

rs = 1 ft, k = s 0.05 * k, S = 20 rs = 10 ft, k = s 0.20 * k, S = 13 .5 rs = 1 ft, ks = 0.20 k, * S = 4.2

1 0.01

Note:

0.1


100

All curves indicate the resulting production increase when the damaged region is eliminated.

Figure 4.3 — When wellbore damage is removed, production increases. The more severe the skin, the more dramatic is the production increase. Skin values here range from 4.2 to 330.

undamaged formation. The figures show that production increase is significant when a severely damaged, or high skin, region is removed. Production increase becomes insignificant at small skin values, i.e., when the magnitude or depth of permeability reduction near the well is small (ks ≥ 0.2k or rs ≤ 1 ft). Note that although acidizing can remove shallow to moderate damage, it is unlikely that it can remove deep damage. Deep damage effects are more likely to be eliminated by fracturing than by acidizing.

35


Cumulative Production Different Fracture Length

Production Increase Due to Fracturing

Npunstimulated /Npdamaged

100

rs = 10 ft, ks = 0.01 * k, S = 330 rs = 1 ft ,k rs = 10 ft,

10

s = 0.01

rs = 1 ft ,k

* k, S = 1 04 ks = 0.0 5 * k, S = 65

s = 0.05 * k, S = 20

rs = 10 ft, k

s

= 0.20

* k, S = 13.5 rs = 1 ft, k s = 0.20 * k, S = 4.2 No Wellbore damage

1 k = 100 md

0.01 Note:

0.1


100

105

k = 100 md rs = 10 ft ks = 0.05 * k S = 65 kfbf = 8,000 md-ft

No Fracture Lf = 5 ft Lf = 15 ft Lf = 40 ft Lf = 80 ft Lf = 150 ft

104

103 0.01

0.1


100

All curves indicate the resulting production increase when a fracture with Lf = 40 ft and kfbf = 8,000 md-ft is applied.

Figure 4.4 — Extending a hydraulic fracture beyond the damaged zone increases production by providing a clear path for wellbore fluids to enter the wellbore. Production increases are shown for a fracture with half-length 40 ft extending through damaged zones having radii of 1 ft and 10 ft and having different degrees of damage.

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106

Figure 4.5 — Once a fracture has extended slightly past the damaged zone, increases in fracture length bring increasingly smaller improvements in cumulative production. In this example, the damaged-zone radius is 10 ft, and the largest cumulative production improvement is noted as the fracture half-length extends from 5 to 15 ft.

Figure 4.4 shows the resulting production increase when a 40-ft fracture with 8,000-md-ft conductivity (equivalent to a dimensionless fracture conductivity, CfD , of 2) is placed in the formation having the referenced amount of damage. The production increases here exceed their damage-removal counterparts in Figure 4.3. Thus, placement of a fracture extending beyond the damaged zone in a high-permeability formation yields a production increase that is at least as large as the resulting production increase for complete removal of the damaged region.

When combined, Figures 4.1 through 4.4 yield the following conclusion: In high-permeability formations, fracturing treatments are expected to yield an insignificant production improvement when there is little or no wellbore damage. However, properly designed fracturing treatments are expected to yield significant production improvement when moderate to high wellbore damage exists. The degree of production improvement increases as wellbore damage increases.

Which treatment, acidizing or fracturing, is better for stimulating production from a damaged, highly permeable zone? The answer depends on which treatment can satisfactorily eliminate the effect of wellbore damage at the least cost. As already noted, acidizing may not provide the required penetration to remove deep damage. An acid treatment may also leave spent acid in the formation, thus creating an additional source of damage. Likewise, a fracture may be difficult to create because of large fluid leakoff; however, a properly designed treatment can overcome this problem. These considerations should be addressed during the design phase of the stimulation treatment.

Effect of Fracture Half-Length Figures 4.5 and 4.6 illustrate the effect of fracture halflength on cumulative production and production increase. The case has been simulated for a damaged formation (rs = 10 ft, ks = 0.05k, S = 65); therefore, all fracture halflengths indicate an increase in production. The largest increase occurs between the 5-ft and 15-ft half-length curves. Note that the fracture for the smaller half-length (5 ft) remained in the damaged region adjacent to the well, and the fracture for the larger half-length (15 ft) propagated out of the region. Thus, a large improvement in production occurs when the fracture is propagated beyond the damaged region.

Cumulative Production

Production Increase

Different Fracture Conductivity

Different Fracture Length

Npstimulated /Npdamaged

Lf = 150 ft Lf = 80 ft Lf = 40 ft Lf = 15 ft

10

k = 100 md rs = 10 ft ks = 0.05 * k S = 65 kfbf = 8,000 md-ft

No Damage, No Fracture

Lf = 5 ft

1


106

100

105

k = 100 md rs = 10 ft, ks = 0.05 * k, S = 65 Lf = 40 ft

kfbf = 20,000 md-ft No Fracture kfbf = 100 md-ft kfbf = 500 md-ft kfbf = 2,000 md-ft kfbf = 4,000 md-ft kfbf = 8,000 md-ft

104

103 0.01

0.1


100

0.01

0.1


100

Figure 4.6 — The gains in production obtained by extending a fracture well past the damaged zone soon diminish to those gains obtained by extending the fracture only slightly past the damaged zone.

Figure 4.7 — Only moderate fracture conductivity is required to improve cumulative production when a fracture extends past the damaged zone. Further increases in fracture conductivity bring increasingly smaller improvements in cumulative production.

Figures 4.5 and 4.6 also indicate that fractures propagated significantly beyond the external radius of the damaged region do not yield a significant production improvement over fractures propagated only slightly beyond the damaged region. This is evidenced by there being only slight shifts in the cumulative production curves at fracture half-lengths exceeding 15 ft. This is also shown by the convergence at the end of 1 year of all production curves corresponding to fracture half-lengths of 15 ft or more.

indicate the depth of wellbore damage. If a fracture is deemed necessary, then permeability, amount of damage, and depth of damage define the desired length of the fracture. If low permeability is present throughout the formation, the objective of the fracture treatment should be to generate large fracture length. Conversely, if the formation is generally of high permeability but with nearwellbore damage, the objective should be to fracture beyond the damaged region.

As stated earlier, in low-permeability formations, fractures effectively extend the wellbore into the formation. Therefore, extension of the fracture is critical in low-permeability formations. In the high-permeability formations discussed here, the fracture is merely a conduit between the well and the undamaged portion of the formation. This is an important observation because leakoff may make it difficult to generate significant length in highpermeability formations. Since the fracture should be designed to extend beyond wellbore damage, it is important that high-permeability wells should be tested prior to fracturing to determine the extent of the damaged zone. A properly designed prefrac well test is helpful because it can reveal formation permeability, skin, and heterogenieties and thus indicate whether a fracture is necessary. Furthermore, analyzing transient data with a radially composite model can

Effect of Fracture Conductivity Figures 4.7 and 4.8 illustrate the effect of fracture conductivity on cumulative production and production increase. This case is simulated for a well with significant wellbore damage (S = 65) and with a fracture that extends beyond the damaged region. The largest production increase occurs at somewhat low fracture conductivity (between 100 md-ft and 2,000 md-ft). When a formation permeability of 100 md is assumed, dimensionless conductivity values are 0.025 and 0.5 for conductivities of 100 md-ft and 2,000 md-ft, respectively. When damaged-zone permeability is assumed to be 5 md, the dimensionless fracture conductivies are 0.5 and 10.0 for conductivities of 100 md-ft and 2,000 md-ft, respectively. Surprisingly, a larger conductivity is not required to significantly improve production in damaged, highpermeability formations.

37


Cumulative Production Different Amounts of Fracture Damage (rs = 10 ft)

Production Increase Different Fracture Conductivity

Npstimultated /Npunstimultated

k = 100 md rs = 10 ft ks = 0.05 * k S = 65 Lf = 40 ft

kfbf = 20,000 md-ft kfbf = 8,000 md-ft kfbf = 4,000 md-ft kfbf = 2,000 md-ft

10

No Damage,

No Fracture

kfbf = 500 md-ft kfbf = 100 md-ft

1


106

100

105

k = 100 md rs = 10 ft ks = 0.05 * k S = 65 Lf = 40 ft kfbf = 8,000 md-ft bfs = 1 ft

No Fracture kfs = 0.001 * k kfs = 0.005 * k kfs = 0.010 * k kfs = 0.050 * k kfs = 0.200 * k

104

103 0.01

0.1


100

Figure 4.8 — Although the gains in production obtained by highly conductive fractures soon converge to those obtained with fractures of more moderate conductivity, fractures that are initially highly conductive are desired because conductivity tends to decrease with time.

0.01

0.1


100

Figure 4.10 — Conditions in this figure are the same as those in Figure 4.9, except that wellbore damage extends 10 ft into the formation and produces a skin of 65. This reduces the production values compared with those of the previous figure, but the general production trends are the same.

Cumulative Production Different Amounts of Fracture Damage (rs = 1 ft) Cumulative Production (STB)

106

105


No Fracture kfs = 0.001 * k kfs = 0.005 * k kfs = 0.010 * k kfs = 0.050 * k kfs = 0.200 * k

104

As stated earlier, in the high-permeability formation discussed here, the fracture serves as a conduit between the well and the undamaged portion of the formation. It is important to generate enough conductivity to make this conduit effective. Because conductivity will typically decline during production,5 the stimulation treatment should generate high initial fracture conductivity so that there will be adequate conductivity throughout production.

103 0.01

0.1


100

Figure 4.9 — As fracture damage increases, cumulative production improvement from fracturing decreases. This example considers various permeability reductions that extend 1 ft into the formation from the fracture face. Skin from wellbore damage is assumed to be 20.

38

Effect of Fracture Damage When a high-permeability formation is fractured, formation damage around the fracture can be expected because fluid leakoff is significant. Figures 4.9, 4.10, 4.11, 4.12, and 4.13 indicate the effects of fracture damage on cumulative production and production increase for two values of wellbore damage. Figures 4.9 and 4.11 correspond to a skin of 20 extending 1 ft into the formation; Figures 4.10 and 4.12 correspond to a skin of 65 extending 10 ft into the formation. The fracture damage was modeled by a zone of reduced permeability parallel to the fracture face and extending 1 ft into the formation. As expected, production improvement decreases with increasing fracture damage;

Production Increase

Production Increase

Different Amounts of Fracture Damage (rs = 1 ft)

Different Amounts of Fracture Damage (rs = 10 ft) 100

No Fracture Damage kfs = 0.200 * k kfs = 0.050 * k

10


kfs = 0.010 k * kfs = 0.005 * k



100

kfs = 0.001 * k

1 0.01

0.1

No Fracture Damage kfs = 0.200 * k kfs = 0.050 * k

kfs = 0.010 k *

10


kfs = 0.005 * k kfs = 0.001 * k

1 1.0 10 Time (months)

100

Figure 4.11 — The increases in production depicted here correspond to the cumulative production values of Figure 4.9.

0.01

0.1


100

Figure 4.12 — The increases in production depicted here correspond to the cumulative production values of Figure 4.10.

Cumulative Production however, production improvement is still significant even with severe fracture damage. Fracture damage must be severe before improved production is significantly limited. Figure 4.13 shows the cumulative production at 2 and 12 months for a range of permeability ratios. The ratios were calculated by dividing fracture-damage permeability by formation permeability. The figure shows that reducing permeability by a factor of 10 makes a small difference after 2 months of production, but to make a difference after 1 year, the reduction factor in permeability must be 100 or greater. The conclusion is that in a high-permeability formation with wellbore damage, even a highly damaged fracture is better than no fracture. A significant decrease in production improvement occurs only when fracture damage is severe or when fracture damage penetrates far into the formation. Similar conclusions were reached in an earlier work dealing with the fracturing of lowpermeability formations.6 Deep damage extending from the fracture can be avoided by properly designing the fracture treatment to minimize excessive fluid loss. For practical purposes, a properly designed and conducted fracturing treatment should result in no productivity impairment from fracture-face damage.

Cumulative Production (MSTB)

Different Amounts of Fracture Damage 400 rs = 10 ft, ks = 0.05 * k, S = 65 rs = 1 ft, ks = 0.05 * k, S = 20

tp = 1 Year

300 200 100 tp = 2 Months

k = 100 md Lf = 40 ft kfbf = 8,000 md-ft bfs = 1 ft

0 0.001

0.01 0.1 Permeability Ratio (kfs/k)

1.0

Figure 4.13 — The permeability reduction around a fracture must be excessive before production is significantly affected. In fact, for the conditions shown, permeability must be reduced by a factor more than 100 to seriously affect cumulative production after 1 year.

39


Reservoir Pressure Distribution


Effect of Rate

Effect of Wellbore Damage 4,000

4,000

No Wellbore Damage

q = 200 STB/D

3,200

tp = 3 Months No Wellbore Damage No Fracture

3,000

1 10 100 Distance from Center of Well (ft)

1,000

Figure 4.14 — Higher production rates cause greater pressure drops in the formation and greater potential for sanding.

PRESSURE PROFILE Sand production is a limiting problem in some high-permeability formations, especially those that are unconsolidated. Sand production reduces the effectiveness of production equipment and, if uncontrolled, can eventually become costly because of damaged equipment. For these reasons, as well as others, many sand-producing wells must be completed with a gravel pack. Unfortunately, a gravel pack can sometimes restrict production much like a region of wellbore damage; therefore, the full potential of some gravel-packed wells is not realized. The magnitude and gradient of the pressure drop created in the formation during production are critical factors related to the potential for sand production. Thus, it is important to examine the pressure profiles of high-permeability formations under various producing conditions.

Effects of Producing Rate and Wellbore Damage The producing rate at the well affects the magnitude and gradient of the pressure drop in the formation during production. Figure 4.14 shows the effect of producing rate on pressure drop after 3 months of production. The results are expected and support intuition: higher rates yield larger pressure drops and steeper pressure gradients in the reservoir. It is thus expected that there is an upper limit on the rate at which a well can be flowed without sand production.

40

2,000

65

2,500

=

3,400

3,000

*k ,S

B/D

0. 05

00 ST

=

q=8

STB/D

,S=8 .3 * k ks = 0 30 S= k, .1 * =0 ks

ks

q = 500

3,600

3,500 Pressure (psi)

Pressure (psi)

3,800

1,500

tp = 3 Months q = 500 STB/D rs = 10 ft No Fracture


1,000

Figure 4.15 — As wellbore damage increases so does pressure drop in the formation. This heightens the chances for sand production.

The amount of permeability reduction in the damaged region also affects the magnitude and gradient of the pressure drop during production. When a well is produced at a constant rate, as is the case in Figure 4.15, the pressure drop will be larger and the pressure gradients will be steeper through a region with a large permeability reduction. Under the assumptions that the mechanical properties of the damaged region remain the same as those of the undamaged region and that the amount of damage has little effect on the mechanical properties of the rock, a well with significant damage in the formation is more likely to produce sand. Consequently, when wellbore damage exists, the producing rate should be limited to control the magnitude and gradient of the pressure drop.

Effect of Fracturing Placing a fracture in the formation significantly alters the producing-pressure profile. Figure 4.16 contrasts pressure profiles for various reservoir conditions and includes profiles already shown in Figures 4.14 and 4.15. The bottommost curve corresponds to a damaged, unfractured formation and shows the largest pressure drop. The next curve up corresponds to an undamaged, unfractured formation and indicates a constant pressure change throughout the reservoir. The topmost two curves were generated under the assumption that a hydraulic fracture was propagated in the same formation as was used for the bottommost curve and that the fracture extended beyond



Effect of Stimulation

Effect of Fracture Length (Distribution is in fracture plane.)

Fracture propagated beyond damage* Fracture propagated beyond damage**

4,000

3,100 2,800

No Damag

3,700

e

2,500

tp = 3 Months q = 500 STB/D rs = 10 ft ks = 0.1 * k


1,000

Note: * Lf = 40 ft, kfbf = 8,000 md-ft Distribution is in fracture plane. ** Lf = 40 ft, kfbf = 8,000 md-ft Distribution is perpendicular to fracture plane.

Pressure (psi)

3,400

D am ag ed ,U ns tim ul at ed

Pressure (psi)

3,700

3,400 3,100 2,800

tp = 3 Months, q = 500 STB/D rs = 10 ft, ks = 0.1 * k, kfbf = 8,000 md-ft e No Damag

D am ag ed ,U nf ra ct ur ed

4,000

2,500

Lf = 5 ft Lf = 15 ft Lf = 40 ft Lf = 80 ft Lf = 150 ft


1,000

Figure 4.16 — Fracturing a well can virtually eliminate the effects of wellbore damage on pressure drop in the formation.

Figure 4.17 — To significantly reduce the effects of wellbore damage on pressure drop in the formation, a hydraulic fracture must extend beyond the damaged zone.

the damaged zone. One of the two curves profiles pressure along the plane of the fracture; the other profiles pressure perpendicular to the fracture plane.

damaged zone. Sand production could be very likely in this case because the pressure drop is significant and pressure gradients are fairly steep from the tip of the fracture to the outer limit of the damaged region. All the remaining fracture pressure profiles correspond to fractures that extend beyond the damaged zone and show small pressure drops and shallow pressure gradients.

The most important observation is that the fracture decreases the pressure drop in the formation relative to both a damaged and an undamaged wellbore condition. Also, the pressure gradients throughout the fractured formation are relatively small, even at the tip of the fracture where the largest pressure drop is expected. Another important point is that the pressure profile does not significantly change as the profiling axis is rotated around the well. Since the pressure drop in a fractured well is less than the pressure drop in an unfractured well, the best solution for limiting sand production appears to be to fracture the formation. In addition, fracturing a damaged well can enable the production improvements shown in earlier sections.

Effect of Fracture Length Figure 4.17 shows the effect of fracture length on pressure drop after producing the well at a constant rate for 3 months. For reference, the figure includes the pressure profiles from Figure 4.16 for an unfractured well with and without wellbore damage. In the fracture pressure profiles, the pressure drop is largest and the gradients are steepest for the fracture that does not propagate past the

It follows that the possibility of sand production is minimized when the fracture is propagated beyond the external radius of the damaged region. Therefore, the fracture should be extended beyond the damaged region to obtain optimum production improvement and to minimize sand production.

Effect of Fracture Conductivity Figure 4.18 shows the effect of fracture conductivity on pressure drop after producing the well at a constant rate for 3 months. Like Figure 4.17, the pressure profiles for an unfractured well with and without wellbore damage are included. In the fracture profiles, the pressure drop is greatest and the pressure gradients are steepest at lower conductivity. Thus, higher fracture conductivities are desired to minimize the pressure drop and pressure gradient within the reservoir during production and thereby reduce the possibility of sand production.

41




Effect of Fracture Conductivity (Distribution is in fracture plane.)

Effect of Fracture Damage (Distribution is in fracture plane.) 4,000

3,100 2,800

kfbf = 100 md-ft kfbf = 500 md-ft kfbf = 2,000 md-ft kfbf = 4,000 md-ft kfbf = 8,000 md-ft kfbf = 20,000 md-ft No Damage

tp = 3 Months, q = 500 STB/D rs = 10 ft, ks = 0.1 * k, Lf = 40 ft kfbf = 8,000 md-ft, bfs = 1 ft

3,400 3,100 2,800

kfs = 0.001 * k kfs = 0.005 * k kfs = 0.050 * k kfs = 0.100 * k kfs = 0.300 * k No Fracture Skin No Damage

2,500

2,500 1 10 100 Distance from Center of Well (ft)

1,000

Figure 4.18 — Higher fracture conductivities result in lower pressure gradients across the formation and minimize the tendency for sand production.

Effect of Fracture Damage Figures 4.19 and 4.20 show the effect of fracture damage on pressure drop and pressure gradient after producing the well for 3 months. Specifically, Figure 4.19 shows the pressure profile along the fracture plane, and Figure 4.20 shows the pressure profile perpendicular to the fracture plane. As expected, larger fracture damage increases the pressure drop and pressure gradient. The pressure gradient is most severe at the tip of the fracture; therefore, the potential for sand production is greatest at this point. It follows that the depth and magnitude of the permeability reduction around a fracture should be minimized for optimum sand control.

CONCLUSIONS The following are the conclusions reached from the numerical simulator study. • Fracturing undamaged, high-permeability formations is not expected to improve production significantly. Therefore, fracturing such formations for the sole purpose of improving production is not recommended. • Fracturing damaged, high-permeability formations should increase production and change the expected pressure profile in the formation, possibly preventing sand production. Thus, fracturing is a viable completion option for high-permeability formations where wellbore damage or the potential for sand production exists.

42

Pressure (psi)

3,700

3,400 D am ag ed ,U nf ra ct ur ed

Pressure (psi)

3,700

tp = 3 Months, q = 500 STB/D rs = 10 ft, ks = 0.1 * k, Lf = 40 ft


4,000


1,000

Figure 4.19 — A high degree of fracture damage can cause an extremely high pressure gradient in the fracture plane near the tip of the fracture.

• Fractures that fail to extend beyond the damaged region in a high-permeability formation will not improve production to optimum levels and will not significantly decrease the potential for sand production. So, when fracturing a high-permeability formation, the fracture should be designed to extend beyond the damaged region. It is unnecessary to generate significant fracture length beyond the external radius of the damaged region; however, it is always prudent to include a safety factor in the fracture design. • Formation permeability, amount of wellbore damage, and extent of wellbore damage must be known to determine the necessity of a fracture and the optimum length and conductivity of the fracture. Hence, to properly design a fracture treatment, it is important to run a prefrac well test to determine permeability and damage parameters. • When fracturing a high-permeability formation, a minimum fracture conductivity is required to improve production and decrease the pressure drop in the formation. The study demonstrated that a dimensionless fracture conductivity greater than 0.5 (based on formation permeability) is adequate. • Fracture conductivity may decline during production. Therefore, to assure that production improvement is maintained and sand production is minimized over the life of the well, the initial conductivity should be greater than the conductivity stated in the previous conclusion.


kf s

=

permeability in the fracture-damaged region, md

ks

=

permeability in the wellbore-damaged region, md

Lf

=

fracture half-length, ft

Effect of Fracture Damage (Distribution is perpendicular to fracture plane.) 4,000

3,400 3,100 2,800


Pressure (psi)

3,700

tp = 3 Months, q = 500 STB/D rs = 10 ft, ks = 0.1 * k, Lf = 40 ft kfbf = 8,000 md-ft, bfs = 1 ft

kfs = 0.001 * k kfs = 0.005 * k kfs = 0.050 * k kfs = 0.100 * k kfs = 0.300 * k No Fracture Skin No Damage

2,500 1 10 100 Distance from Center of Well (ft)

1,000

Figure 4.20 — When fracture damage is large, high pressure gradients can arise across the wellbore-damaged zone perpendicular to the plane of the fracture.

• Fracture damage limits production improvement and increases the pressure drop and gradient; however, the fracture damage must be severe before a pronounced effect is detected. In particular, permeability damage in the near-fracture vicinity must be great or damage must penetrate deep into the formation before there is a significant decline in production improvement and a pronounced pressure drop. Proper design of the fracture treatment can minimize deep damage away from the fracture.

NOMENCLATURE bf

=

fracture width, ft

bf s

=

distance fracture damage extends into formation from fracture face, ft

Bo

=

formation volume factor for oil, RB/STB

cf

=

formation compressibility, psi-1

co

=

oil compressibility, psi-1

ct

=

total compressibility, psi-1

h

=

formation thickness, ft

k

=

formation permeability, md

kf bf =

fracture conductivity, md-ft

Np =

cumulative oil production from beginning of production, STB

pi

initial reservoir pressure, psia

=

pwf =

flowing bottomhole pressure, psia

q

=

surface production rate, STB/D

re

=

external radius of the formation, ft

rs

=

radius of wellbore-damaged region, ft

rw

=

wellbore radius, ft

S

=

wellbore-damage skin, dimensionless

tp

=

production time, months

=

fluid viscosity, cp

e

=

formation effective porosity, fraction

REFERENCES 1. Gidley, J.L., et al.: Recent Advances in Hydraulic Fracturing, Monograph Series, SPE, Richardson, Texas (1989) 12. 2. Prasad, R.K., and Coble, L.E.: “Horizontal Well Performance Simulation,” Paper SPE 21087, Latin American Petroleum Engineering Conference, Rio De Janeiro, October 14-19, 1990. 3. Krueger, R.F.: “An Overview of Formation Damage and Well Productivity in Oilfield Operations,” JPT (February 1986) 131152. 4. Hawkins, M. F., Jr.: “A Note on the Skin Effect,” Trans., AIME (1956) 207, 356-357. 5. McDaniel, B.W., and Parker, M.A.: “Accurate Design of Fracturing Treatment Requires Conductivity Measurements at Simulated Reservoir Conditions,” Paper SPE 17541, SPE Rocky Mountain Regional Meeting, Casper, Wyoming, May 11-13, 1988. 6. Holditch, S.A.: “Factors Affecting Water Blocking and Gas Flow from Hydraulically Fractured Gas Wells,” JPT (December 1979) 1514-1524.

43


44

Chapter 5 INTRODUCTION Halliburton’s FracPac Completion Service involves hydraulically fracturing high-permeability formations. The goal of the service is to improve production from formations with deep, severe damage and to restore the productivity of wells with sand production problems. Well testing can aid in determining whether a well is a candidate for FracPac completion and, if so, can provide some of the important parameters needed in designing the completion. Furthermore, a post-treatment well test can assist in evaluating the effectiveness of the treatment and can furnish valuable information for refining completion design for future wells in the area.

applied mainly to low-permeability formations, hydraulic fracturing can also be beneficial in higher-permeability formations.

This chapter discusses the use of well-test data as applied to FracPac completions, provides a general overview of well-testing methods and equipment, and presents a recently derived procedure for using well-test data for type-curve analysis in formations with low dimensionless fracture conductivities. A theoretical example details the calculations that are typically encountered in the analysis, and two field examples illustrate the application of the procedure to actual wells.

Higher-permeability formations (10 md ≤ k ≤ 500 md) can also benefit from fracture stimulation, especially if there is deep formation damage around the wellbore. These are the type of formations to which FracPac completions are usually applied. The effects that wellbore damage, fracture length, fracture conductivity, and fracture damage have on production when this completion method is used were discussed in the previous chapter. To obtain the best improvement in production from a FracPac completion, a highly conductive fracture that extends past the region of wellbore damage should be created.

PERMEABILITY INFLUENCE ON FRACTURING EFFECTIVENESS Fracturing is a widely used stimulation process for enhancing well productivity. Formation permeability, k, plays a large role in how effective a fracturing treatment can be. Although traditionally

Well Testing

In low-permeability formations (k < 10 md), hydraulic fracturing increases the effective wellbore radius by changing the flow profile to the well from radial flow to linear flow. The linear flow of fluids into a highpermeability channel formed by a hydraulic fracture reduces the flow pressure drop, especially in the nearwellbore region. Thus, the drag force and induced stress on formation particles decline, preventing formation fines migration and sand production.

In very high permeability formations (k > 500 md), productivity increases slightly with fracturing. In general, as reservoir permeability increases, the benefits of creating longer fractures decreases. In the very high permeability formations, increasing the fracture

45


length will result in only marginal improvements in productivity. Thus, long fracture lengths may not be economically prudent. Acid stimulation may restore the productivity only if the decline in flow is from shallow skin damage around the wellbore. Theoretically, though, hydraulic fracturing will improve productivity more than matrix acidizing as long as the fracture penetrates past the damaged zone.

to as a tester valve, is run into the hole on drillpipe or tubing. The pressure inside the tubing or drillpipe is isolated by the tester valve and is low compared to the hydrostatic pressure from the column of fluid in the hole and the pressure of the reservoir. Once on bottom, the packer is set, isolating the zone of interest. When the tester valve is opened, the formation is exposed to the lower pressure, and formation fluids are allowed to enter the drillpipe or tubing.

WELL TESTS

When the tester valve is closed, a pressure builds up below the valve as the formation repressures the area around the wellbore. Depending on equipment configuration, the tester valve can be repeatedly opened and closed as desired to create multiple flowing and shut-in periods.

Information from a properly conducted well test can be used to simply determine the amounts and types of produced fluids or to perform sophisticated pressure transient analysis. Some tests may be considered to be productivity or deliverability tests that can aid in selecting well completion methods and in designing artificial lift systems and production facilities. Other types of well tests are used to determine formation damage or stimulation effects related to an individual well or to determine reservoir characteristics such as permeability, pressure, volume, and heterogeneity.

Application to FracPac Operations In particular, a well test may be used to determine whether production can be improved by a FracPac completion or by another completion or stimulation method such as sand control, massive hydraulic fracturing, or matrix, fracture, or closed-fracture acidizing. If FracPac completion services are performed, a posttreatment well test may provide fracture half-length and conductivity, formation permeability and pressure, and the amount of wellbore skin removed or fracture skin remaining. Additionally, the reduction in pressure drop around the fracture and the wellbore may be calculated to determine whether the lowered pressure drops are sufficient to suppress or control sand production. All this posttreatment information serves to establish the FracPac treatment’s degree of success and is valuable in further improving the stimulation technique for application in adjacent wells.

Technique and Equipment Commercial methods for well testing have been available since 1926. Over the years, the actual methods employed in well testing have in essence remained unchanged even though the equipment employed has become increasingly complex. In its most basic form, a bottomhole assembly consisting of a packer and a surface-operated valve, normally referred

46

In addition to a tester valve and one or more packers, a typical testing assembly will include safety joints; jars; one or more tools that permit the string contents to be circulated; mechanical or electrical devices that record pressure and temperature; and sometimes samplers. Offshore and hostile environments may require the use of additional components such as slip joints and various safety devices such as subsea trees, lubricator/retainer valves, safety valves, and circulating/safety valves. Conventional test tools are adequate for testing many formations. However, interpretation of highly productive zones may be difficult because of flow restrictions imposed by such tools. In these cases, full-opening tools, typically with a 2.25-inch inside diameter (ID) and a 5.0-inch outside diameter (OD), can be used to produce the zone of interest at a higher rate. Such tools also allow various wireline operations such as production logging or perforating to be carried out through the toolstring. These full-opening test strings are also suitable for the various types of stimulation, especially those involving proppant. Both conventional and full-opening tools are available in a range of sizes. As tools with smaller ODs are used, the flow area through the tool decreases. In the case of smaller full-opening tools, the tools remain fully open but have a reduced ID. There are two general methods of operating test tools. The first method depends on manipulation (reciprocation and rotation) of the test string to control the flow of the well. Conventional tools and a limited selection of full-opening tools are operated in this fashion. With the second method, once the packer has been set or the seal assembly is in the permanent packer, no further string manipulation is required until the end of the test. The flow of the well is controlled hydraulically by the application and release of pressure. The second method is preferred for operations

Isobaric Pressure Transients for a Hydraulically Fractured Formation (CfD = 0.1) CfD = 0.1 pwf = 388 psi ∆p = 168.4 psi pi = 4,900 psi q = 200 STB/D tp = 200 hours Lf = 50 ft bf = 0.05 ft

Isobaric Pressure Transients Flow Streamlines

Figure 5.1 — When fracture conductivity is low, the flow profile around the well is essentially radial, and flowing bottomhole pressure is relatively low.

from floating vessels or in hostile environments. Testing in harsh environments may require the modification of objectives to accommodate the physical limitations of the testing equipment, well-control equipment, casing, and mud or hole fluid. Several factors can influence the mechanical success of a well test. Particularly important, whether in cased or open hole, is the condition of the mud or hole fluid. This one factor has the single greatest impact on the operation of test tools. Mud in poor condition can prevent the operation of test tools by either of the two methods and can also prevent retrieval of the toolstring in some cases. To a certain extent, the types of elastomers used in the tools is

determined by the mud or hole fluid as well as the temperature and the produced fluid. Other major factors that affect the success of the test are the condition and profile of the hole or casing and the condition of the test string. All of these issues as well as the objectives of the test must be considered long before the actual testing operation. Detailed, objective planning that results in written procedures that are accepted and understood by all concerned parties leads to a successful testing operation. Since the nature of well testing, which by intent should result in the production of hydrocarbons, is inherently hazardous, safety considerations must always be paramount in the planning process.

47


Isobaric Pressure Transients for a Hydraulically Fractured Formation (CfD = 1.0) CfD = 1.0 pwf = 2,509 psi ∆p = 168.4 psi pi = 4,900 psi q = 200 STB/D tp = 200 hours Lf = 50 ft bf = 0.05 ft

Flow Streamlines

Isobaric Pressure Transients

Figure 5.2 — As fracture conductivity increases, the flow profile around the well becomes increasingly elliptical, and bottomhole flowing pressure increases.

A MODEL FOR ANALYZING WELL-TEST DATA Azari et al.1-3 presented a versatile model for the pressure transient analysis of hydraulically fractured wells. This model has the broadest range of physical wellbore, fracture, and formation parameters available in the petroleum industry. The solution and the provided type-curves are even applicable for situations in which the flow in a hydraulically fractured formation resembles a radial geometry with a negative skin factor, where pseudoradial flow prevails in a short period of time. Fractures extending only a few feet in the formation, high skin on the fracture

48

combined with short fracture half-length, and very low conductivity fractures are a few examples of the extreme application of the model with near-radial pressure behavior. This model can also be applied for well testing of FracPac completions which generally have low dimensionless fracture conductivity and short fracture half-length. Before the analysis model is presented, important concepts regarding dimensionless fracture conductivity and skin damage are discussed.

Isobaric Pressure Transients for a Hydraulically Fractured Formation (CfD = 10) CfD = 10 pwf = 2,605 psi ∆p = 168.4 psi pi = 4,900 psi q = 200 STB/D tp = 200 hours Lf = 50 ft bf = 0.05 ft


Figure 5.3 — The increase in flowing bottomhole pressure is much larger between Figures 5.1 and 5.2 than between Figures 5.2 and 5.3, although the factor (10) by which fracture conductivity increases is the same for each pair of figures.

Dimensionless Fracture Conductivity Dimensionless fracture conductivity, CfD , is defined by kf bf Cf D . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5.1) kLf where kf is fracture permeability, bf is fracture width, and Lf is fracture half-length. In FracPac completions, the value of bf is high, while both k and kf are medium and Lf is short. The combination of these parameters is such that the value of CfD happens to be on the low side. For example, in a 100-md formation, a fracture with a halflength of 40 ft and having fracture conductivity ranging

from 100 md-ft to 10,000 md-ft produces a dimensionless fracture conductivity of 0.025 to 2.5. A hydraulic fracturing treatment that results in a low dimensionless fracture conductivity should not be assumed a failure. Prats4 indicated that for a given fracture volume, an increase in the width results in a short fracture, and the maximum production rate is obtained when the value of a certain variable, a, is about 1.25 (this corresponds to CfD ≈ 1.26). As a matter of fact, the majority of well tests performed on hydraulically fractured wells reveal CfD values of 1 to 10. As the dimensionless fracture conductivity drops below 2, the fracture productivity decreases rapidly, and the fracture becomes less significant while the pressure

49


Isobaric Pressure Transients for a Hydraulically Fractured Formation (CfD = 100) CfD = 100 pwf = 2,768 psi ∆p = 168.4 psi pi = 4,900 psi q = 200 STB/D tp = 200 hours Lf = 50 ft bf = 0.05 ft


Figure 5.4 — In the subject well, further increases in fracture conductivity above 1 continue to increase the ellipticity of the flow profile but bring only moderate increases in flowing bottomhole pressure.

distribution approaches radial flow. Prats indicated, “The pressure distribution for a ≥ 100 (CfD ≤ π/200) is very nearly the same as that for radial flow.” Even though the dimensionless fracture conductivity of a FracPac completion is low, the productivity of the well increases. There are two reasons for the increase. First, the fracture extends beyond the damaged zone around the wellbore, which changes the well’s flow profile from radial to linear or elliptical. Second, sand production is controlled. In a hydraulically fractured well, productivity is a function of fracture conductivity, fracture half-length, and fracture skin, Sf . For a constant flow rate, wellbore pressure increases as Sf decreases and as CfD or Lf increases. 50

Figures 5.1 through 5.5 show the flow profiles in a 5-md formation with a fracture half-length of 50 ft after 200 hours of production for dimensionless fracture conductivities of 0.1 to 1,000. For a constant fracture length, the flowing bottomhole pressure, pwf , increases with CfD . The largest pressure increase (from 388 to 2,509 psia) occurs when the dimensionless fracture conductivity changes from 0.1 to 1.

Skin Damage An important factor that can reduce the benefits of hydraulic fracturing is the introduction of skin damage on the fracture face. Such damage can be attributed to

Isobaric Pressure Transients for a Hydraulically Fractured Formation (CfD = 1,000) CfD = 1,000 pwf = 2,575 psi ∆p = 168.4 psi pi = 4,900 psi q = 200 STB/D tp = 200 hours Lf = 50 ft bf = 0.05 ft


Figure 5.5 — At high fracture conductivities, there is an increase in the fraction of fluid flowing through the fracture to the wellbore and a decrease in the fraction flowing directly through the formation to the wellbore. This causes the flow profile to be elliptical rather than radial.

• Incompatibility of fracturing and formation fluids, the mixing of which can cause clay swelling in the formation5 • Dispersion of formation fines, with subsequent bridging effects at pore throats5 • Imbibition processes and relative permeability alterations resulting from liquid movement and condensation (more evident in tight gas reservoirs) • Insufficient cleaning of the formation following a fracturing job • Unbroken fracturing gels

• Proppant crushing and embedment Linear skin damage, Sf , as defined by Equation 5.2, limits fluid flow to the fracture because the damage covers an extended area on both faces of and alongside the fracture. By comparison, radial-flow skin damage, S, as defined by Equation 5.3, covers a much smaller fluid cross-sectional area but with a higher flux per unit area. Radial-flow skin damage is the same as wellbore damage, which has been discussed earlier. k Sf 1 kfs

bfs . . . . . . . . . . . . . . . . . . . . . . . . . . (5.2) 2Lf

51


Production Increase Different Amounts of Fracture Damage


100 No Fracture Damage, Sf = 0 kfs = 0.200 * k, Sf = 0.157 kfs = 0.050 * k, Sf = 0.746

kfs = 0.010 k, S * f = 3.89

10

kfs = 0.005 k, S * f = 7.82

k = 100 md rs = 10 ft ks = 0.05 * k S = 65 Lf = 40 ft kfbf = 8,000 md-ft CfD = 2 bfs = 1 ft

kfs = 0.001 * k, Sf = 39.23

1 0.01

0.1


100

Figure 5.6 — After fracturing, this well would have a productivity improvement of about 24 at 0.01 month of production, if there were no fracture damage. If there were fracture damage that reduced the surrounding formation permeability by a factor of 100 to depth of 1 ft from the fracture, the productivity improvement would only be about 11. Such fracture damage corresponds to a fracture skin of about 3.9.

160-acre spacing (i.e., an effective drainage radius, re , of 1,500 ft) reduces the flow by a factor of 18.6. By comparison, the linear skin damage that was just mentioned reduces productivity by a factor of 2.2. _ kh p pwf r qo 141.2oBo ln e S0.75 . . . . . . . . . . . . . (5.4) rw

_ where qo is oil flow rate, h is reservoir thickness, p is average reservoir pressure, pwf is flowing bottomhole pressure, o is oil viscosity, and Bo is formation volume factor for oil. This comparison shows that in a nonfractured formation, linear skin damage around a fracture face does not reduce productivity as much as the radial damage around the wellbore. This is due to the extended cross-sectional area for flow in hydraulically fractured formations. Damage must be severe and must extend deep into the formation before it can significantly reduce the productivity of a hydraulically fractured formation.

Analysis Model for Low Dimensionless Fracture Conductivity where kfs is permeability in the fracture-damaged zone and bfs is the depth of the fracture-damaged zone as measured from the face of the fracture. k r S 1 ln s . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5.3) kfs rw

where k is permeability in the wellbore-damaged zone, rs is the outer radius of the wellbore-damaged zone, and rw is the radius of the wellbore. For the well presented in Figure 5.6, at 0.01 month of production, the productivity improvement of about 24 with no fracture damage would drop to about 11 if permeability were reduced by a factor of 100 to a depth of 1 ft away from the fracture face. From Equation 5.2, the value of this linear skin damage is 3.9. Whereas, for a nonfractured well with a radius of 0.35 ft, Equation 5.3 yields a radial skin damage of 134 for a similar 1 ft of damage, but with the damage measured around the wellbore instead of away from the fracture face. According to the pseudosteady-state equation for radial flow of fluids given by Equation 5.4, a skin value of 134 in a formation with

52

For high-conductivity fractures, fluid flow in the formation is essentially perpendicular to the fracture face for a significant period. As fracture conductivity decreases, fluid flow in the formation parallel to the fracture plane increases proportionally to provide the least resistant fluid flux path. This adds to the complexity of the solution by changing a one-dimensional flow problem to a two-dimensional flow problem. The resultant fluid flux is directed toward the wellbore much like a radial flow pattern but with an elliptical radius of investigation. The shapes of the elliptical isobaric pressure transients approach a circular profile with time. Decreasing the fracture’s conductivity and half-length and increasing the damage on the fracture face will expedite this transition. The well-test data for FracPac stimulations will exhibit an early-time wellbore-storage period, followed by a transition period, and finally will display pseudoradial flow. This behavior is similar to that of unstimulated wells. As the fracture conductivity and half-length increase, an intermediate transition to bilinear flow will start, but true bilinear flow will not be formed. This extended transition will only change the pressure profile by creating a longer transition from storage-dominated flow to pseudoradial flow. This behavior is also similar to that found with a radial flow profile with a higher negative skin. Thus, the

Pressure and Pressure-Dervative Type Curves Finite-Conductivity, Vertical Fractures With Wellbore Coverage (No Fracture Skin) 102 pwD

Sf = 0.0 ηfD = 1012

101

10-2 = CfD * hfD

10-1

10-1 100 10-2 102

10-3 w

=

S

103 -1

10

-2

10

-3

10

-4

10

-5

10

10

-6

-7

10

10-4

p‘wD * tfD

101

fD

pwD and p‘wD * tfD

100

10-5 10-12

10-9

10-6

10-3

100

103

tfD

Figure 5.7 — These pressure and pressure-derivative type-curves apply to vertical fractures with zero fracture skin and account for wellbore-storage effects. Note that as wellbore-storage effects increase, the effects of fracture conductivity decrease.

near-radial pressure responses of a FracPac well could lead the operator to doubt the existence of a propped hydraulic fracture. Figure 5.7 shows the pressure and pressure-derivative type-curves that account for the influence of both wellbore storage and fracture conductivity with zero fracture skin. These type-curves show that the influence of fracture conductivity diminishes as the value of dimensionless wellbore storage, SwfD , increases. Since SwfD increases when Lf decreases, it follows that the creation of a highconductivity fracture is not warranted when fracture halflength is short. The separation between the curves having different conductivity values increases as the dimensionless wellbore storage decreases (Lf increases) down to 10-4 and stays constant thereafter. Therefore, the fracture halflength should be designed to be long enough to gain the maximum benefit of a high-conductivity fracture. These results and observations agree with the published4, 6, 7 productivity increase curves. Two regions in Figure 5.7 have radial flow behavior. The first region is located in the rightmost area of the diagram and represents the short fracture-half-length scenario.

When fracture half-length is short, regardless of the value of fracture conductivity, a pseudoradial flow profile forms as wellbore storage dies out. The second region that represents all the low dimensionless fracture conductivity situations is located at the top of Figure 5.7. For these low CfD cases, pseudoradial flow forms even before the pressure transients reach the tip of fracture. Cinco-Ley8 showed that flow near the tip of the fracture is negligible for the low-conductivity fractures, and radial flow prevails beyond a critical fracture half-length. Azari et al.1 stated that as the dimensionless fracture conductivity decreases below 0.1, the pressure drop in the fracture increases more rapidly, causing the transients to move progressively faster in the formation and slower in the fracture. Thus, as the dimensionless fracture conductivity gets lower, the elliptical pressure transients gradually become circular. When the dimensionless fracture conductivity is below 0.1, the shapes of the isobaric pressure transients are so nearly circular that a radial flow pattern prevails in the formation even before the isobaric pressure transients reach the tip of the fracture. Thus, the duration of the bilinear flow

53


Pressure and Pressure-Dervative Type Curves Finite-Conductivity, Vertical Fractures With Wellbore Storage (Fracture Skin Present)

100

pwD

2.5 = Sf

CfD * hfD = 1 ηfD = 1012

101 10-1 10-2

10-1

100 fD

p‘wD * tfD

-1

10

-3

10

10

10

-5

=

S

w

10-2

-7


101

10-3 10-10

10-7

10-4 tfD

10-1

102

Figure 5.8 — The pressure and pressure-derivative type-curves displayed here apply to vertical fractures and account for fracture skin and wellbore-storage effects. When there is no fracture damage and wellbore storage is low, early flow (unit slope) is followed by bilinear flow (quarter slope), linear flow (half slope), and pseudoradial flow. Increases in wellbore storage decrease the duration of bilinear flow. As fracture skin increases, the period of wellbore storage increases, and there is a quicker change to pseudoradial flow.

period decreases with the decrease in dimensionless fracture conductivity and completely disappears when dimensionless fracture conductivity is below 0.05. Since linear flow in the formation does not develop for the low-conductivity fractures, the end of the bilinear flow also corresponds to the start of the transition to pseudoradial flow. Decreasing the dimensionless fracture conductivity reduces the duration of the bilinear flow to a point that bilinear flow ends at such early times that it may be concealed by wellborestorage effects. Therefore, regardless of the size of the fracture half-length, the transient pressure profile for low dimensionless conductivity fractures exhibits near-radial flow behavior following the end of wellbore-storage effects. Figure 5.8 shows that the increase of linear fracture skin will cause the pressure profile of hydraulically fractured wells to resemble radial flow behavior. Shorter fracture half-length (corresponding to higher Lf -based dimensionless wellborestorage coefficient, SwfD ) and lower dimensionless fracture conductivity serve to enhance this resemblance. In hydraulically fractured formations, pseudoradial flow develops when the transients in the form of isobaric ellipses propagate into the formation away from the tip of the fracture and approach a circular shape. In the analytical

54

solution of Azari et al., pseudoradial flow is asymptotically tied to the trilinear transform in such a way that the pressure drop never exceeds an equivalent radial flow.1, 2 As long as the dimensionless fracture conductivity is above 2, the onset of pseudoradial flow occurs when dimensionless time based on fracture length, tf D , is 1.3. Pseudoradial flow starts progressively earlier for fracture conductivities below 2 and also with the increase in linear fracture skin combined with short fracture half-length1 since the transition for such cases is independent of fracture half-length. The pressure response of a fractured well under pseudoradial flow is similar to the response of a radial flow geometry with either an enlarged (apparent) wellbore radius, rwa , or an improvement in near-wellbore permeability, yielding an apparent negative radial flow pseudoskin, S′. The following equations represent the semilog straight-line behavior of the pseudoradial flow: 1 PwD (ln twD 2S′0.80908) . . . . . . . . . . . . . . . . . (5.5) 2 where pwD is dimensionless pressure and twD is dimensionless time based on wellbore radius.

rwa rweS ′ . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5.6a) Flow-Efficiency Control Parameters for a Hydraulically Fractured Well

or, solving for S′, 100

rw S ′ln . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5.6b) rwa

Combining Equations 5.5 and 5.6b yields

10-2

1 PwD (ln twD 2Sc 0.80908) . . . . . . . . . . . . . . . . (5.8) 2 where tfD is dimensionless time based on Lf , and Sc is an equivalent radial flow pseudoskin that is a function of fracture conductivity, linear fracture skin, and fracture half-length as shown in the following equation. rwa e Sc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5.9a) Lf or, solving for Sc , Lf Sc ln . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5.9b) rwa

=

Sf

ηfD = 1012

1.0

10-4

0.0 1

where twaD is the dimensionless time based on rwa , and γ is Euler’s constant (1.78107). Equation 5.7 can be rearranged to provide Equations 5.8 and 5.9:

0 0.

2.5

rwa / Lf

0.1

1 1 4 PwD (ln twaD 0.80908) ln twaD . . . (5.7) 2 2

10-6

10-8 10-3

10-1

101

103

CfD

Figure 5.9 — Fracture conductivity, fracture length, and fracture skin control flow efficiency in a hydraulically fractured well. As fracture conductivity increases, the ratio of apparent wellbore radius to fracture length ultimately becomes essentially constant at a value that depends upon fracture skin.

Combining Equations 5.6b and 5.9b results in Lf Sc S′ln . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5.10) rw

Figure 5.9 shows the relationship between CfD , Lf , and Sf , which are the flow-efficiency control parameters in a hydraulically fractured well. This plot demonstrates that the rate of increase of rwa /Lf with CfD diminishes to a point that rwa /Lf is essentially a constant value of 0.5 for zero linear skin, when CfD is greater than 100π. Therefore, the pseudoradial flow of an infinite-conductivity fractured well can be represented with a radial-flow expression, similar to Equation 5.7, that has an apparent wellbore radius of one-half the fracture half-length. As noted by Cinco-Ley et al.9 the solution for such a case is basically the same as the infinite-conductivity solution of Gringarten et al.10

As the ratio of rwa /Lf decreases below 0.5, the value of rwa approaches rw , and consequently, S′ approaches zero. According to Equation 5.5, as the negative value of S′ declines, the appearance of a fractured well under pseudoradial flow approaches the profile of an unstimulated well. Figure 5.9 indicates that the ratio rwa /Lf decreases as the fracture conductivity decreases and as skin on the fracture increases. Thus, greater radial-flow performance and lower fracture productivity will be achieved when one moves downward through the series of characteristic curves. In Figure 5.9, the characteristic curve with dimensionless conductivity less than 0.1 and without linear fracture skin can be represented by a straight line of unit slope. The following equation describes this straight-line portion of the characteristic curves presented in Figure 5.9:

55


rwa 0.18Cf D Lf

for Cf D 0.1 . . . . . . . . . . . (5.11)

tf D 1 PwD ln ln Swf De 2Sc0.80908 . . . (5.15) 2 Swf D

or, solving for rwa , 0.18kf bf rwa k

for Cf D 0.1 . . . . . . . . . . . (5.12)

Cinco-Ley et al.8 presented a similar relationship for low-conductivity cases. Equation 5.12 indicates that rwa is independent of fracture half-length when both fracture conductivity is very low, and bilinear flow ends and pseudoradial flow starts before the isobaric pressure transients reach the tip of the fracture. When CfD < 2, the fracture half-length investigated prior to formation of pseudoradial flow is less than the true fracture half-length. This length, defined as effective fracture half-length, Lfe , continues to decline with lower CfD down to about CfD = 0.1, below which the effective wellbore radius and thus the effective fracture half-length are both independent of Lf . For a given formation, the excess fracture half-length created above the effective fracture half-length will not improve productivity. For fractures with CfD < 0.1, this concept can be applied to obtain an effective fracture half-length corresponding to CfD = 0.1 that is the start of the unit-slope line on the characteristic curve of Figure 5.9. In other words, a fracture with CfD < 0.1 behaves the same as a fracture with CfD = 0.1 but with an effective fracture half-length that is shorter than the true Lf . Using this assumption in Equation 5.11 results in an effective fracture half-length of 55 rwa . This number is very sensitive to the start of the straight line on the characteristic curve. For instance, if it is assumed that the straight line starts at CfD = 0.2, the effective fracture half-length equals 27.8rwa . Cinco-Ley et al.8 report a value of 35rwa as a critical fracture halflength. Most of the effective fracture half-lengths calculated for the very low-conductivity fractures fall between 25rwa and 55rwa . 25rwa Lfe 55rwa . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5.13) A more convenient form of presenting Equations 5.5 and 5.8 results when skin and storage are parameterized together: twD 1 PwD ln ln CDe2S ′ 0.80908 . . . . . . (5.14) CD 2

56

where CD is dimensionless wellbore-storage coefficient.

The following equalities can easily be established between the parameters defined for radial flow and the corresponding fracture flow variables: tf D twD = . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5.16) CD Swf D CDe 2S ′ Swf D e 2Sc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5.17) As long as CfD is about or below 0.1, Equation 5.11 can be combined with Equation 5.15 to yield the following relationships: tf D 1 PwD ln Cf D ln Swf De 3Sc 0.916 2 Swf D

. . . . . . . . . . (5.18)

tf D Swf D 1 PwD ln ln 2 4.24 . . . . . . . . . (5.19) 2 Swf D Cf D

tf D 1 PwD ln 2 4.24 . . . . . . . . . . . . . . . . . . . . . (5.20) 2 Cf D

The data for the low-conductivity fractures in which the pressure profile resembles near-radial flow behavior were grouped together and presented in Figure 5.10. The parameterized groups of Equation 5.18 are used in this type-curve. It has been observed that there may be multiple matches in the postfrac analysis of a hydraulically fractured well. A unique solution can only be obtained if the data includes both the well storage and pseudoradial flow responses, or they contain at least those measurements made after the transient responses from the tip of the fracture began to affect wellbore pressures. If data include storage effects, and the permeability is known from a prefrac pressure test, multiple solutions can be prevented because the y-axis match is predetermined. For FracPac stimulations, pseudoradial flow prevails rather quickly, allowing for a unique match of the data with the models based on either Figure 5.7 or Figure 5.10.

Pressure and Pressure-Derivative Type Curves Low-Conductivity Hydraulic Fractures

101

3S

-2

p‘wD * tfD

2

0 x1 5 3 6 0 10 x 1 4 3 5 0 10 x 1 3 3 4 0 10 x 1 3 3 10

10

6

pwD

3

10-1

2

x

100

*

Sw

30

10


fD

=

c

e

10 10-2

10-1

100

101

102

103

(tfD /SwfD) * CfD

Figure 5.10 — These type-curves were developed to account for the pseudoradial flow behavior that occurs in wells with low-conductivity hydraulic fractures.

ANALYSIS EXAMPLES

A Theoretical Example

The technique presented here for the evaluation and analysis of short fractures induced in high-permeability formations is unique in the petroleum industry. The model has more fracture and formation parameters than any other available model in the industry.1-3 The solutions are accurate over extreme ranges of the parameters and are beyond the limits of accuracy of other available models. The ranges shown for wellbore storage, conductivity, skin values, and time presented in the type-curves of Figures 5.7, 5.8, and 5.10 are not available anywhere else. Halliburton was the first to present solutions and typecurves for the dimensionless fracture conductivities below 0.1, and still there is no other solution available below 0.01.

This example illustrates the pressure transient analysis for a FracPac stimulation. The induced fracture for a highpermeability reservoir may not effectively bypass all of the skin damage around the wellbore, leaving behind a small positive or negative apparent radial-flow pseudoskin value.

The following examples demonstrate the application of the type-curves shown in Figures 5.7 and 5.10 to the analysis of low-conductivity fractured wells in which the pressure responses resemble near-radial flow profiles.

An analytical design model was employed to generate 48 hours of theoretical pressure buildup for a fractured well in an undersaturated oil reservoir. The design model generates pressure versus time values based on the appropriate pwD and tD functional relationship for a particular reservoir system. Table 5.1 displays rock and fluid data. Table 5.2 gives the pressures, rate schedule, cumulative times, and plotting function11, 12 values used in the analysis. Figure 5.11 presents the log-log type-curve match, and Table 5.3 shows analysis results. In this example, the presence of a short fracture half-length has prevented the development

57


Table 5.1 — Basic Reservoir Properties for Theoretical Example Parameter

Value

System

Oil

Dynamic Pay Thickness, ft

5

Initial Pressure, psia

6,014.65

Oil Viscosity, cp

0.45

Reservoir Temperature, °F

150

System Compressibility, 1/MMpsi

15

Effective Porosity

7%

Oil Compressibility, 1/MMpsi

12

Oil Formation Volume Factor, RB/STB

1.0

Wellbore Radius, ft

0.25

Oil Rate, STB/D

200

Producing Time, hours

24

Table 5.2 — Time, Pressure, and Plotting Function Values for Theoretical Example Pt.

Time,

Pressure,

Pressure,

Equivalent

psia

Time, hours

psi

No. hours

Pt.

Time,

Pressure,

Pressure,

Equivalent

psia

Time, hours

psi

No. hours

1 2 3 4 5

24.0 24.0 24.0 24.0 24.0

4,180.36 4,210.78 4,240.06 4,268.39 4,295.88

2.400E+01 9.996E-03 1.998E-02 2.996E-02 3.993E-02

* 3.042E+01 5.970E+01 8.803E+01 1.155E+02

26 27 28 29 30

28.0 29.0 30.0 32.0 33.0

5,729.87 5,764.18 5,789.38 5,824.97 5,838.27

3.429E+00 4.138E+00 4.800E+00 6.000E+00 6.545E+00

1.550E+03 1.584E+03 1.609E+03 1.645E+03 1.658E+03

6 7 8 9 10

24.1 24.1 24.1 24.1 24.1

4,322.58 4,348.55 4,398.42 4,445.73 4,490.61

4.990E-02 5.985E-02 7.973E-02 9.959E-02 1.194E-01

11.422E+02 1.682E+02 2.181E+02 2.654E+02 3.103E+02

31 32 33 34 35

34.0 36.0 38.0 40.0 42.0

5,849.60 5,867.95 5,881.97 5,893.59 5,903.32

7.059E+00 8.000E+00 8.842E+00 9.600E+00 1.029E+01

1.669E+03 1.688E+03 1.702E+03 1.713E+03 1.723E+03

11 12 13 14 15

24.1 24.2 24.2 24.2 24.3

4,532.26 4,572.12 4,610.20 4,646.50 4,730.45

1.392E-01 1.589E-01 1.787E-01 1.983E-01 2.474E-01

3.519E+02 3.918E+02 4.298E+02 4.661E+02 5.501E+02

36 37 38 39 40

44.0 46.0 48.0 50.0 52.0

5,911.50 5,918.52 5,924.61 5,929.95 5,934.68

1.091E+01 1.148E+01 1.200E+01 1.248E+01 1.292E+01

1.731E+03 1.738E+03 1.744E+03 1.750E+03 1.754E+03

16 17 18 19 20

24.3 24.4 24.5 24.6 24.8

4,805.79 4,934.96 5,040.98 5,128.83 5,264.03

2.963E-01 3.934E-01 4.898E-01 5.854E-01 7.742E-01

6.254E+02 7.546E+02 8.606E+02 9.485E+02 1.084E+03

41 42 43 44 45

54.0 56.0 58.0 60.0 62.0

5,938.89 5,942.68 5,946.09 5,949.19 5,952.02

1.333E+01 1.371E+01 1.407E+01 1.440E+01 1.471E+01

1.759E+03 1.762E+03 1.766E+03 1.769E+03 1.772E+03

21 22 23 24 25

25.0 25.5 26.0 26.5 27.0

5,361.34 5,504.16 5,586.44 5,640.13 5,678.29

9.600E-01 1.412E+00 1.846E+00 2.264E+00 2.667E+00

1.181E+03 1.324E+03 1.406E+03 1.460E+03 1.498E+03

46 47 48 49 50

64.0 66.0 68.0 70.0 72.0

5,954.61 5,956.99 5,959.19 5,961.22 5,963.11

1.500E+01 1.527E+01 1.553E+01 1.577E+01 1.600E+01

1.774E+03 1.777E+03 1.779E+03 1.781E+03 1.783E+03

Table 5.3 — Log-Log Type-Curve Analysis Results for Theoretical Example Parameter Type-Curve Match, pw D

1

Oil Permeability, md

10.17

Type-Curve Match, (tf D /Swf D ) * Cf D

0.1

Fracture Half-Length, ft

48.6

Data Plot p, psi

250

Fracture Conductivity, dimensionless

0.048

Data Plot te′ hours

0.168

Fracture Conductivity, md-ft

23.7

Apparent Radial Flow Pseudoskin, S ′

-0.515

Apparent Wellbore Radius, rwa ′ ft

0.418

Swf D

e3Sc

Wellbore Storage Constant, SwfD ′ dimensionless

58

Value

3x

105

0.1935

Type-Curve Matching

Log-Log Type-Curve Match Theoretical Example

104 ∆p and d(∆p)/d[In(∆te)] (psi)

of any commonly recognizable fracture flow regime. The data exhibit well-storage effects at early time followed by transition to pseudoradial flow. The type-curve match was performed with an on-screen type-curve matching program that draws a series of analytical curves on the screen and allows the user to “drag” the actual well-test data until a match is achieved. The software automatically calculates formation and fracture parameters from the selected match. The manual calculations to obtain the analysis results for the typecurves illustrated in Figure 5.10 follow. The type-curve analysis technique for Figure 5.7 follows the basic typecurve matching mechanics presented in Earlougher’s Advances in Well Test Analysis.13

CfD = 0.048 SwfD = 0.1935 SwfD * e3Sc = 3 * 105 S‘ = -0.515 Lf = 48.6 ft

103 D

6

102

∆p

c 3S

10

=

S wf

*

e

3 * 105 105

The following match data were recorded from the onscreen type-curve matching program:

d(∆p)/d[In(∆te)]

101

• type-curve: pwD = 1

10-1

• data plot: ∆p = 250 psi

100 ∆te (hours)

101

102

Figure 5.11 — A theoretical problem involving a lowconductivity hydraulic fracture was solved by on-screen typecurve matching in which the type-curves of Figure 5.10 were used. The results are shown here.

• type-curve: (tfD/SwfD)CfD = 0.1 • data plot: ∆te = 0.168 hour • SwfDe3Sc = 3105

Type-Curve Solution 1. Obtain permeability from the dimensionless pressure equation: 141.26qo Bo o pwD ko h p

for oil . . . . . . . . (5.21a)

where ∆p is pressure difference. 1,424qgTpwD kg hDm(p)

for gas . . . . . . . . . (5.21b)

2. Calculate wellbore-storage coefficient, Cw , from the unit-slope line: 1 Cw qoBo t/ punit slope for oil . . . . . . . . (5.22a) 24 1 Cw qg Bg t/ punit slope for gas . . . . . . . . (5.22b) 24 where Bg is formation volume factor for gas.

where kg is formation permeability to gas, qg is gas flow rate, T is reservoir temperature, D is turbulent flow coefficient, and m(p) is pseudopressure. ko = [41.26(200 STB/D)(1 RB/STB)(0.45cp)(1)]/

Cw = [(1/24)(200 STB/D)(1 RB/STB)][(0.1 hour)/ (312.4 psi)] Cw = 0.0027 bbl/psi

[(250)(5 ft)] ko = 10.17 md

59


Log-Log Type-Curve Match

∆m(p) and d[∆m(p)]/d[In(∆te)] (psi2/cp)

Field Example 1 (Gas Well) 109

108

CfD = 0.072 SwfD = 0.173 SwfD * e3Sc = 8 * 104 S‘ = -0.126 Lf = 22.2 ft

rwa /Lf = (0.18)(0.048) = 0.0086 6. Use Equation 5.9b to evaluate Sc : ∆m(p)

c 3S

fD

107

5

3*

10

=

*

e

Sw

8 * 104 3 * 104

106 10-2

5. Apply Equation 5.11 to calculate rwa /Lf since the value of CfD is less than 0.1. Otherwise, Figure 5.9 would be used.

d[∆m(p)]/d[In(∆te)]

10-1 100 ∆te (hours)

101

Figure 5.12 — Type-curve analysis was performed on postfrac pressure-buildup data from a well that had proved difficult to bring onto production. The on-screen analysis used the typecurves of Figure 5.10 to generate these results.

Sc = ln(1/0.0086) = 4.75 7. Obtain SwfD from the following equation, where M indicates that the value of the expression is obtained from curve matching:

/

Swf D Swf D e3ScM e3Sc . . . . . . . . . . . . . . . . . . . . . . . . . (5.25) SwfD = 3x105/e3x4.75 = 0.1935 8. Calculate the apparent radial-flow pseudoskin using Equation 5.17: 1 S′ = ln Swf D e3Sc CD eSc . . . . . . . . . . . . . . . . . . . . . (5.26) 2

/

3. Obtain dimensionless wellbore storage from the following relationship: 5.615Cw ................................................(5.23) CD 2 ct hrw2 where φ is formation porosity and ct is the total compressibility of the formation matrix. CD = [5.615(0.0027 bbl/psi)]/[2π(0.07)(1510-6 psi-1) (5 ft)(0.25 ft)2] CD = 7,266 4. The x-axis of the type-curve in Figure 5.10 can be reduced to the following relationship:

/

0.0003kht

S′ = 1/2 ln (3x105 / 7,266 e4.75) = -0.515 9. Use Equation 5.6a to calculate apparent wellbore radius: rwa = (0.25 ft)e-(-0.515) = 0.418 ft 10. Using rwa from Step 9 and rwa/Lf from Step 5, calculate Lf from the following equation:

/ /

Lf rwa rwa Lf . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5.27) Lf = (0.418 ft)/(0.0086) Lf = 48.6 ft

Cf D . . . . . . . . . . . (5.24) tf D Swf D Cf D C

11. Use k, CfD , and Lf calculated from Steps 1, 4, and 10, respectively, to determine fracture conductivity:

Use Equation 5.24 to calculate CfD from the x-axis match of the type-curve and the data plot:

kf bf Cf D kLf . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5.28)

w

CfD = [(0.1)(0.45 cp)(0.0027 bbl/psi)]/[(0.0003) (10.17 md)(5 ft)(0.168)] CfD = 0.048

kf bf = (0.048)(10.17 md)(48.6 ft) = 23.7 md-ft 12. Estimate the effective fracture half-length using Equation 5.13: Lfe = 10 ft to 23 ft

60

Table 5.4 — Basic Reservoir Properties for Field Example 1 Parameter

Value

System

Gas


21


2,006

Well Stream Gas Gravity

0.6565


155

Gas Viscosity, cp

0.017

Effective Porosity

7.6%


383

Water Saturation

28.0%

Gas Compressibility, 1/MMpsi

528

Gas Formation Volume Factor, RB/Mscf

1.296

Wellbore Radius, ft

0.328

Table 5.5 — Log-Log Type-Curve Analysis Results for Field Example 1 Parameter

Value

Type-Curve Match, pw D

1

Gas Permeability, md

4.47

Type-Curve Match, (tf D /Swf D ) x Cf D

0.1


22.2

Data Plot m(p), psia2/cp

1.8 x 107


0.072


0.082


7.16


-0.126


0.289

Swf D

e3Sc


8x

104

0.173

Field Example 1

Field Example 2

The operator of this gas well was experiencing difficulty in bringing the well on production. A prefracture buildup test was not run on this well because the operator had problems initiating any significant flow prior to the fracture treatment. A hydraulic fracturing treatment consisting of 1,429 bbl of gel plus 90,000 lb of 16/30 Ottawa sand was pumped into the formation. After a 5-hour wait for fracture closure, the well was flowed back on an 8/64-inch choke. At the end of the ensuing 136.5-hour flowback period, 800 bbl of fracturing fluid were still unrecovered. The gas rate had stabilized at 1,928 Mscf/D prior to the initiation of the 78.5-hour postfracture pressure buildup test. Basic reservoir data for this system are given in Table 5.4. Analysis of the postfracture pressure buildup data was accomplished with the previously mentioned on-screen type-curve matching software.

A 94-hour pressure buildup test was run on this oil well, which was producing from a dolomite formation. This well was acid-fractured earlier in its life, and the reservoir pressure was below the bubble point at the time of the test. Rock and fluid data for this case are presented in Table 5.6.

The type-curve matching results presented in Table 5.5 and Figure 5.12 yielded an effective permeability to gas of 4.47 md, a fracture half-length of 22.2 ft, and a fracture conductivity of 7.16 md-ft. The data indicate wellbore-storage effects at early time, with transition to pseudoradial flow regime.

The type-curve matching results presented in Table 5.7 and Figure 5.13 were accomplished by using on-screen type-curve matching software based on Figure 5.7. A radial-flow type-curve analysis of the data yielded ko = 3.34 md, S = -4.06, and CD = 9.82102, while the linear regression of the straight-line semilog data provided an effective permeability to oil of 3.8 md and a radial skin factor of -3.79. This example illustrates that the pressure transient test of a hydraulically fractured well having a short fracture half-length resembles radial flow behavior even if fracture conductivity is high.

61


Table 5.6 — Basic Reservoir Properties for Field Example 2 Parameter

Value

System

Oil/Gas


6


2,995

API Gravity of Oil, °API

44


209

Bubble Point GOR, scf/STB

714

Effective Porosity

10%

Bubble Point Pressure, psia

3,000

Water Saturation

35%

Separator Gas Gravity

0.62

Pressure for PVT Properties, psia

2,220

Oil Viscosity, cp

0.365

Oil Formation Volume Factor, RB/STB

1.363


126

Wellbore Radius, ft

0.328

Oil Compressibility, 1/MMpsi

189

Table 5.7 — Log-Log Type-Curve Analysis Results for Field Example 2 Parameter

Value

Type-Curve Match, pw D

1

Oil Permeability, md

3.96

Type-Curve Match, tf D

10-2


28.6

Data Plot m(p), psi/cp

7.2 x 102


50


5,663

10-2


3.6 x


0.14

Fracture/Matrix Diffusivity, dimensionless

1012

Skin on the Fracture, dimensionless

0.01


-3.75

Fracture Height, dimensionless

1


13.95

Log-Log Type-Curve Match

∆m(p) and d[∆m(p)]/d[In(∆te)] (psi2/cp)

Field Example 2 (Oil Well)

103

102

CfD ≥ 50 SwfD = 0.14 Sf = 0.01 S‘ = -3.75 ηfd = 1012 Lf = 28.6 ft

NOMENCLATURE bf = fracture width, ft

∆m(p)

bf s = depth of fracture-damaged zone, as measured from fracture face, ft Bg = formation volume factor for gas, RB/Mscf

d[∆m(p)]/d[In(∆te)]

Bo = formation volume factor for oil, RB/STB 101

Cf D = fracture conductivity, dimensionless 10-2

10-1

100

∆te (hours)

101

102

Figure 5.13 — The on-screen type-curve analysis that produced these results was based on the type-curves of Figure 5.7. The well had been acid-fractured earlier in its life.

ct = formation matrix total compressibility, psi-1 CD = wellbore-storage coefficient, dimensionless Cw = wellbore-storage coefficient, bbl/psi D = turbulent flow coefficient, q-2 h = reservoir thickness, ft hf D = fracture height, dimensionless

62

k = formation permeability, md

T = reservoir temperature, °R

kf = fracture permeability, md

te = equivalent time, hours

kg = formation permeability relative to gas, md ko = formation permeability relative to oil, md ks = permeability of wellbore-damaged zone, md kf s = permeability of fracture-damaged zone, md Lf = fracture half-length, ft

p

p dp , psi / cp (p)z(p) 2

for gas

p

dp , psi / cp (p)B (p)

z = gas compressibility factor, dimensionless

p = pressure difference, psia = hydraulic diffusivity ratio, dimensionless

po

po

twaD = dimensionless time, based on apparent wellbore radius

= Euler’s constant, 1.78107

m(p) = pseudopressure

m(p)

tp = producing time, hours

twD = dimensionless time, based on wellbore radius

Lf e = effective fracture half-length, ft

m(p)2

tf D = dimensionless time, based on fracture half-length

for oil

o

PwD = wellbore pressure, dimensionless pwf = bottomhole flowing pressure, psia _ p = surface production rate, STB/D qg = gas flow rate, Mscf/D qo = oil flow rate, STB/D re = effective reservoir drainage radius, ft rs = external radius of wellbore-damaged region, ft rw = wellbore radius, ft rwa = apparent wellbore radius, ft S = wellbore-damage skin, dimensionless S′ = apparent radial flow pseudoskin, dimensionless Sc = equivalent radial flow pseudoskin, dimensionless Sf = linear-flow skin damage (fracture-damage skin), dimensionless Swf D = wellbore-storage coefficient, dimensionless

o = oil viscosity, cp = formation porosity, fraction

REFERENCES 1. Azari, M., Wooden, W.O., and Coble, L.E.: “A Complete Set of Laplace Transforms for Finite-Conductivity Vertical Fractures Under Bilinear and Trilinear Flows,” Paper SPE 20556, 1990 SPE Annual Technical Conference and Exhibition, New Orleans, September 23-26. 2. Azari, M., Wooden, W.O., and Coble, L.E.: “Further Investigation on the Analytic Solutions for Finite-Conductivity Vertical Fractures,” Paper SPE 21402, SPE Middle East Oil Technical Conference and Exhibition, Manama, Bahrain, November 16-19, 1991. 3. Azari, M., et al.: “Performance Prediction for Finite-Conductivity Vertical Fractures,” Paper SPE 22659, 1991 SPE Annual Technical Conference and Exhibition, Dallas, October 6-9. 4. Prats, M.: “Effect of Vertical Fracture on Reservoir Behavior– Incompressible Fluid Case,” SPEJ (June 1961) 105-118. 5. Azari, M.: “Formation Permeability Damage Induced by Completion Brines,” JPT (April 1990) 486-492. 6. Tinsley, J.M., et al.: “Vertical Fracture Height–Its Effect on Steady State Production Increase,” JPT (May 1969) 633-638. 7. Soliman, M.Y.: “Modifications to Production Increase Calculations for a Hydraulically Fractured Well,” JPT (January 1983) 170-172. 8. Cinco-Ley, H., Ramey, H.J., Jr., and Rodriguez, F.: “Behavior of Wells With Low-Conductivity Vertical Fractures,” Paper SPE 16776, 1987 SPE Annual Technical Conference and Exhibition, Dallas, September 27-30.

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9. Cinco-Ley, H., Samaniego, V.F., and Dominguez, A.N.: “Transient Pressure Behavior for a Well With a Finite-Conductivity Vertical Fracture,” SPEJ (August 1978) 253-254. 10. Gringarten, A.C., Ramey, H.J., Jr., and Raghavan, R.: “UnsteadyState Pressure Distribution Created by a Well With a Single Infinite-Conductivity Vertical Fracture,” SPEJ (August 1974) 347-360; Trans., AIME, 257. 11. Agarwal, R.G.: “A New Method to Account for Producing Time Effects When Drawdown Type-Curves Are Used to Analyze Pressure Buildup and Other Test Data,” Paper SPE 9829, 1980 SPE Annual Technical Conference and Exhibition, Dallas, September 21-24. 12. Al-Hussainy, R., Ramey, H.J., and Crawford, P.B.: “The Flow of Real Gases Through Porous Media,” JPT (May 1966) 624-636; Trans., AIME, 237. 13. Earlougher, R.C., Jr.: Advances in Well Test Analysis, Monograph Series, SPE, Dallas (1977) 5, 24-27.

64

Chapter 6 INTRODUCTION Some of the formation parameters used in designing a FracPac job can be obtained from wireline logging measurements. These parameters include stress, shale volume, pressure, and permeability. Necessary data can be obtained from tools run in open holes; however, some of the data cannot be acquired in cased wells.

WIRELINE MEASUREMENTS The wireline measurements used in FracPac design are obtained primarily from sonic, gamma, density, and formation tester devices. Sonic and density tools provide the measurements needed to calculate formation stresses, while gamma tools are the main instruments for determining shale volume. Formation testers give information from which formation pressure and permeability may be derived, although these parameters are often obtained by other means.

Advantages Sonic, gamma, and density tools move continuously through the wellbore as they make their measurements. Measurements are recorded as a function of depth, typically every 0.25 ft or 0.10 m. Because of this dense sampling of formation properties, these measurements are often considered as being continuous. When dense data such as this is used in the FracPac simulator and other programs for designing fracturing jobs, it allows for improved vertical resolution of stress variations, thereby enhancing design results.

Rock mechanical properties such as Poisson’s ratio, Young’s modulus, shear modulus, and bulk compressibility are calculated from wireline measurements as an intermediate step in determining formation stress. When rock properties are derived from acoustic measurements, they are referred to as dynamic measurements; when derived otherwise, they are referred to as static measurements. Thus, log-derived rock properties are dynamic properties. Rock properties obtained from cores can be dynamic or static, depending on whether the measurements were obtained with acoustic devices. Since there can be a considerable difference between corresponding dynamic and static properties, it is important to distinguish which type is under consideration in discussions and calculations.

Design Logging

When rock properties are determined from measurements made with the rock in its natural environment, such as with logging measurements, the properties are referred to as in-situ properties. When the properties are determined from measurements made with the rock out of its natural environment, such as with core measurements, the properties are referred to as ex-situ properties. As with dynamic and static properties, there can be a marked difference between in-situ and ex-situ values. The coring process itself stresses the sample, possibly affecting the sample’s mechanical properties. This is especially possible in unconsolidated rock, where often a core cannot be retrieved. Furthermore, shale dehydration can affect measurements on shaly cores since the mechanical properties of shales are directly related to their water content. When the rock properties are finally measured at the surface, the

65


conditions on the core are often quite different from those in the formation from which the core was retrieved. Determining rock properties from logging data eliminates the effects of core damage and of pressure and fluid changes that occur during core retrieval. To ensure that the dynamic rock properties and the resulting stress field components that are calculated from logging measurements correlate with the actual values of these parameters, the calculated values should be calibrated using microfrac data.

Sonic Measurements Acoustic energy propagates through matter as waves, the most commonly known being compressional and shear waves. Acoustic slowness is the time required for an acoustic wave to travel a specified distance through a material, usually 1 ft or 1 m. Slowness is usually expressed in microseconds per foot (s/ft) or microseconds per meter (s/m). Using acoustic sources and sensors, wireline sonic tools measure a formation’s compressional and shear slowness, tc and ts , respectively. These are the two acoustic parameters needed in determining formation stresses. Two types of sonic tools can be used to measure tc and ts , depending on whether the formation is slow. A formation is slow when ts > t f , where t f is borehole fluid slowness. (The nominal value of t f for water is 189 s/ft.) Full waveform sonic tools, such as Halliburton’s Full Wave Sonic, use monopole acoustic transmitters and receivers to generate and sense compressional and shear waves that travel along the borehole wall. The tools are thus able to measure tc and ts . When the formation is slow, laws of physics dictate that monopole tools cannot give rise to shear waves along the borehole wall and so cannot measure ts . In slow formations, a dipole sonic tool, such as Halliburton’s Low Frequency Dipole, is run. A dipole acoustic transmitter generates flexural waves that travel along the borehole wall and are sensed by dipole receivers to measure flexural slowness. At low frequencies, flexural waves travel with the same slowness as shear waves; thus, measuring flexural slowness is tantamount to measuring shear slowness. Dipole tools also contain monopole acoustic transmitters and receivers to enable compressional slowness to be measured. Figure 6.1 presents a dipole sonic log.

Density Measurements Formation density, also known as formation bulk density and designated b ′ is the combined mass per unit volume

66

of all materials in the formation, whether solid, liquid, or gas. Wireline density tools contain a chemical source of gamma rays and two gamma ray detectors. Gamma rays are emitted by the source into the formation, with some of the gamma rays being scattered back to the tool and sensed by the detectors. The density measurement is based on the assumption that as formation density increases, the number of gamma rays scattered back to the tool decreases. The measured bulk density is used to determine overburden pressure, po. Bulk density and overburden pressure are used with tc and ts in computing formation stresses. Either traditional or spectral density tools can be used in open holes to measure b . Traditional density tools measure gamma radiation returning to the tool in a single broad energy range. By contrast, spectral density tools measure the amounts of gamma radiation returning to the tool in several specific energy ranges. The spectral tools can provide a more accurate b measurement and also furnish a measurement of formation photoelectric factor useful in identifying formation lithology.

Gamma Ray Measurements Wireline gamma ray tools contain a gamma ray detector but no gamma ray source. They measure the amount of gamma radiation present in the subsurface environment. The amount of such radiation emanating from a geologic formation is usually a good indicator of the formation’s shale volume, Vsh . Shale volume is used in determining the formation’s sanding potential. Gamma ray tools are often run in combination with sonic and density tools. Either a conventional or spectral gamma ray tool can be used. Conventional tools measure gamma radiation in a single broad energy range while spectral tools measure the amounts of gamma radiation in a large number of energy bands. With spectral data, Vsh can be calculated more accurately, and clay types can be identified. Other tools are sometimes used to determine shale volume. These include spontaneous potential, neutron, neutrondensity combination, and resistivity devices; however, they will not be discussed here.

Formation Tester Measurements Formation testers provide stationary measurements of formation pressure. The tool is positioned at a depth at which pressure is to be measured and is then held stationary while pressure is recorded as a function of time. This contrasts with most other logging tools, whose

Dipole Sonic Log

Figure 6.1 — Dipole sonic logs display both compressional and shear slowness curves, as in Track 2 of this example. The compressional/shear acoustic velocity ratio and dynamic Poisson’s ratio are plotted in Track 3. The acoustic velocity ratio is the reciprocal of the shear/compressional slowness ratio and is essential in calculating the dynamic value of Poisson’s ratio and other rock properties. The Gamma Ray curve in Track 1 is used for correlation with formations in offset wells, and the Caliper curve indicates severe washouts that could affect the quality of sonic measurements.

67


measurements are usually recorded as a function of depth. Analysis of pressure measurements yields reservoir pressure and permeability. These parameters are used directly in the FracPac simulation program. Pore pressure, pp ′ is one of the most crucial parameters in evaluating the stress field around the borehole. Although the assumption of a 0.46-psi/ft pore pressure gradient is accurate enough for most analyses, the exceptions will cause erroneous stress profile calculations. For example, overpressured zones and depleted zones drastically affect the final stress profile. Although the pore pressure gradients in such zones are generally known from reservoir engineering, the precise boundaries at which pressure gradients change must be identified. This can be accomplished using wireline formation tester or microfrac data. If such data are not available, overpressured or depleted zones may be detected using density, resistivity, or sonic logs. Pore pressure gradients can vary on a smaller scale within a reservoir or zone of interest, depending upon the density of the fluid present. Although a slight gradient shift may not be critical in the final stress evaluation, data from a wireline formation tester should be used whenever it is available. Density, resistivity, and sonic logs and reservoir engineering data are usually not able to sufficiently resolve variations in pore pressure gradients within an interval.

FRACTURING CALCULATIONS Acoustic velocity ratio, Poisson’s ratio, Young’s modulus, shear modulus, and bulk compressibility can be calculated from tc , ts , and b . Equations 6.1 through 6.5 can be used and the results displayed in a log format as in Figure 6.2. In all the equations that follow, measurement units must be compatible for calculations; otherwise, conversion factors must be applied.

ts Rv . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6.1) tc where Rv is acoustic velocity ratio, ts is shear acoustic slowness, and tc is compressional acoustic slowness. ∆ts and tc are determined from wireline sonic tool measurements. 2R v2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6.2) 2 1R v2 where is dynamic Poisson’s ratio.

68

b 43R v2 t 2 1R 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6.3) s v where E is dynamic Young’s modulus, and b is formation bulk density determined from wireline density tool measurements.

b G ts 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6.4) where G is dynamic shear modulus. 3ts2 cb . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6.5) b 3R v24 where cb is dynamic bulk compressibility. The results from Equations 6.1 through 6.5 can then be used to determine the formation’s effective radial, tangential, and shear stresses and fracture closure pressure. Biot’s constant, overburden pressure gradient, and mud pressure must be calculated before the stresses and fracture pressures can be found. Equations 6.6 through 6.8 outline the necessary relationships. 1cm

cb . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6.6) where is Biot’s constant, and cm is matrix compressibility, which can be determined from laboratory measurements on full core samples or can be estimated. Dfm poG b dD . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6.7) D 0

where poG is overburden pressure gradient, D is depth, and Dfm is the depth of the formation under study. pm mDf m . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6.8) where pm is mud or fluid pressure due to the mud or fluid column in the wellbore, and m is the average mud or fluid weight from the surface to the formation under study. Formations stresses and fracturing pressures can now be found with Equations 6.9 through 6.13. (Equations 6.9 through 6.12 are after Coates and Denoo.1) Log analysis

Rock Properties Log

Figure 6.2 — The Rock Properties log presents dynamic values of Poisson’s ratio, Young’s modulus, shear modulus, and bulk compressibility (Tracks 3 and 4). It also displays an estimated static Poisson’s ratio (Track 3). The sonic and density measurements on which the rock property calculations are based are shown in Track 2.

69

FRACPAC COMPLETION SERVICES FRACPRESSURE Log

Figure 6.3 — The FRACPRESSURE log provides estimates of the vertical extent that will be achieved by a hydraulically induced fracture. In Track 3, formation lithology and fluid content are shown. Track 1 plots a formation stress profile that helps identify stress contrasts and barriers to fracture growth. In particular, the log displays fracture closure pressure, which is equal to the least principal horizontal stress. Track 2 plots the fracture extension pressure and shows estimates of the vertical height growth that will occur as pressure is increased in 200-psi increments. 70

programs such as Halliburton’s STRESS Module can perform the necessary calculations and display the results in log format as in Figure 6.3

r pm ppG Df m . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6.9)

Mohr's Circle Analysis Linear Failure Envelope

where r is effective radial stress, and ppG is pore pressure gradient, which can be determined from wireline formation tester measurements.

D ra

pm Dfm ppG 2 poG ppG R 1

Failure Envelope

Shear

Initial Shear Stress

wn

Envelope Slope

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6.10)

where is minimum effective tangential stress, and R is the regional stress, which can be determined from measurements on full cores or can be estimated.

wdo

Stress

Radial Stress Tangential Stress

pfi t . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6.11) where pf i is fracture initiation pressure, and t is tensile strength, which can be determined from measurements on full core samples.

pfc Dfm ppG 1

p

oG

Figure 6.4 — The drawdown pressure needed to calculate a formation’s critical pressure can be found by determining the distance between Mohr’s circle and the formation’s failure envelope. The envelope can be linear or parabolic.

– ppG . . . . . . . (6.12)

where pfc is fracture closure pressure. Tf 1 1 pfe2 pfe1 L L f2 f1

2 Lf 2

pfc2 pfc1 arccos . . . . . . . . . . . . . . . (6.13) Lf 1 where pfe2 is the fracture extension pressure needed to extend the fracture from one zone (Zone 1) into an adjacent zone (Zone 2), pfe1 is the fracture extension pressure in Zone 1, Tf is fracture toughness (a stress intensity factor at the ends of the fracture), Lf2 is the fracture’s half-length after extension into Zone 2, Lf1 is the fracture’s half-length before extension into Zone 2, pfc2 is the fracture closure pressure in Zone 2, and pfc1 is the fracture closure pressure in Zone 1. The log-derived Young’s modulus and fracture closure pressure are used in the FracPac simulation program to design the FracPac job. The program is built upon a three-dimensional fracture model and is described in Fracture Design Simulators (Chapter 7). Other STRESS

Module results are used in Halliburton’s Perforating Planner Module (described in Chapter 11) to estimate the downhole performance of perforating systems used in FracPac completions.

SANDING CALCULATIONS The log-derived stresses calculated in the previous section are used in Mohr’s Circle analysis to predict formation sanding potential. This analysis determines a formation’s critical pressure, which is the pressure at which the formation will experience shear failure. Critical pressure varies with depth and can be calculated by subtracting mud pressure from drawdown pressure, the latter of which can be found from Mohr’s Circle analysis. As shown in Figure 6.4, the distance between the Mohr circle and the formation’s failure envelope (which can be linear or parabolic) defines the drawdown pressure. Critical pressure can be calculated from the relationships in Equations 6.14 through 6.25 and then displayed on a log as in Figure 6.5. (Equations 6.14 and 6.15 are after Edwards, Sharma, and Charron.2)

71


Formation Strength Log

Figure 6.5 — A Sanding Potential and Formation Strength log shows the critical sanding pressure curve and the maximum drilling pressure curve. Safe bottomhole pressures are indicated by the shaded area between the curves. At pressures less than the critical pressure, sanding can occur; at pressures higher than the maximum drilling pressure, formation fracturing can occur. The pore pressure curve gives the static pressure of the fluid in the formation pore space, and the overburden pressure curve gives the pressure exerted by the weight of overlying rock.

cu E 0.0045 1 Vsh 0.008Vsh . . . . . . . . . . . (6.14) where cu is the uniaxial compressive strength, and Vsh is the formation’s shale volume, which can be determined from wireline gamma ray as well as other wireline measurements. 0.025cu si . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6.15) cb 106 where si is initial shear strength of the formation.

r rM . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6.16) 2 where rM is the radius of Mohr’s circle and represents s , which is the net, or effective, shear stress on the formation. The x-coordinate, xM , of the center of Mohr’s circle is given by Equations 6.17 and 6.18. xM s

when r . . . . . . . . . . . . . . . . . . (6.17)

xM r s

when r . . . . . . . . . . . . . . . . . . (6.18)

When the Mohr’s circle analysis involves a linear failure envelope, Equations 6.19 through 6.21 are used.

72

m( r ) r si 2 m xi . . . . . . . . . . . . . . . . . . . . . (6.19) 1 m m where xi is the x-coordinate of the intersection of the failure line with the Mohr’s circle radius that is tangent to the failure line, and m is the slope of the failure line. yi si mxi . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6.20) where yi is the y-coordinate of the intersection of the failure line with the Mohr’s circle radius that is tangent to the failure line.

RECOMMENDED LOGGING PROGRAM Logging data should be recorded in open boreholes where possible. A basic data set can still be gathered in a cased well, but openhole data are more accurate and complete.

Openhole Environment Sonic, density, formation tester, and gamma ray logs should all be run in open holes. Small-diameter sonic, density, and gamma ray tools rated for high-pressure, high-temperature work are available for use in slimhole applications and hostile environments. For example, Halliburton’s HEAT Suite tools have 2.75-inch OD and are rated to 25,000 psi and 500˚F.

2 dM x

y x 2 i – M i . . . . . . . . . . . . . . . . . . . . . . . . . . (6.21)

where dM is the distance from the center of Mohr’s circle to (xi ,yi ). When a parabolic failure envelope is used in the Mohr’s circle analysis, Equation 6.22 applies.

dM 2i

1 1 xM 2si . . . . . . . . . . . . (6.22) si

where dM is the distance from the center of Mohr’s circle to the intersection of the Mohr’s circle radius that is tangent to the failure line, and is the offset of the parabolic failure envelope. ( should be greater than 2si .) For either a linear failure envelope or a parabolic failure envelope, if dM > rM , then the formation is strong enough to withstand stresses and remain intact; otherwise, there is potential for sanding. Drawdown and critical pressures, pdraw and pcrit , can be calculated from Equations 6.23 through 6.25. pdraw dM rM

when r . . . . . . . . . . . . . . . (6.23)

pdraw dM rM

when r . . . . . . . . . . . . . . . (6.24)

pcrit pm pdraw . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6.25)

Cased-Hole Environment With the exception of density, all measurements made in open holes can be made in cased wells. Because of the presence of casing, however, special tools or tool configurations must sometimes be used. In cased holes, full waveform sonic tools can provide good measurements when there is good acoustic coupling between casing and cement. This coupling serves to damp the acoustic waves that are propagated through the casing so they will not interfere with the acoustic waves that are returning from the formation. The Full Wave Sonic tool can be configured in an extra-long mode in which the receivers are offset from the transmitter by additional space. This increases the difference in arrival times at the receivers between the casing waves and the formation waves so that the two wave types are easier to distinguish from one another. In certain cases, waveform filtering may improve the measurements, even when the casing-cement acoustic coupling is not optimal. Casing is translucent to dipole acoustic energy. Dipole tools can determine ts in cased wells, even when there is no cement present between the casing and the formation. However, in such an environment, tc cannot be measured and must be obtained from an openhole log. Formation bulk density cannot be measured in cased wells. If an openhole density log is not available, density can be estimated from compressional acoustic information, but the accuracy of rock property and subsequent calculations will diminish. Special formation testers must be used in cased wells. They contain explosive charges that penetrate casing and cement to establish hydraulic communication between the tool and

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the formation. Since these tools are configured with only a few charges, they can measure formation pressure at only a few discrete depths in the well. For instance, Halliburton’s Cased Hole Formation Tester contains two perforating charges, so it can record pressure at two different depths.

poG = overburden pressure gradient pp = formation pore pressure ppG = formation pore pressure gradient rM = radius of Mohr’s circle

DATA TRANSFER All logging data, computations, and analysis results are stored on magnetic media and are easily transferrable among personal computers, workstations, and mainframe computers.

NOMENCLATURE cb = dynamic bulk compressibility cm = matrix compressibility cu = uniaxial compressive strength D = depth Df m = depth of subject formation dM = distance from center of Mohr’s circle to the point (xi ,yi) on the failure line E = dynamic Young’s modulus G = dynamic shear modulus

Tf = fracture toughness Vsh = formation shale volume xM = x-coordinate of the center of Mohr’s circle (xi ,yI ) = coordinates of the intersection of the failure line with the Mohr’s circle radius that is tangent to the failure line

= Biot’s constant tc = formation acoustic compressional slowness tf = borehole fluid acoustic slowness ts = formation acoustic shear slowness

= dynamic Poisson’s ratio b = formation bulk density

Lf 1 = fracture half-length after extension into Zone 1

m = average mud or fluid weight from surface to subject formation

Lf 2 = fracture half-length after extension into Zone 2

r = effective radial stress

pcrit = critical pressure

R = regional stress

pdraw = drawdown pressure pfc = fracture closure pressure

si = initial formation shear strength t = formation tensile strength

pfc1 = fracture closure pressure in Zone 1

= minimum effective tangential stress

pfc2 = fracture closure pressure in Zone 2

= offset of parabolic failure envelope in Mohr’s circle analysis

pfe1 = pressure needed to extend fracture into Zone 1 pfe2 = pressure needed to extend fracture into Zone 2 pfi = fracture initiation pressure pm = mud or fluid pressure due to the mud or fluid column in the wellbore po = overburden pressure

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Rv = acoustic velocity ratio

REFERENCES 1. Coates, G.R., and Denoo, S.A.: “Mechanical Properties Program Using Borehole Analysis and Mohr’s Circle,” Paper SPWLA 1981 DD, 1981 SPWLA Annual Logging Symposium, June. 2. Edwards, D.P., Sharma, Y., and Charron, A.: “Zones of Sand Production Identified by Log-Derived Properties: A Case Study,” Paper S, 1983 European Formation Evaluation Symposium, March.

Chapter 7 INTRODUCTION The purpose of a fracture design simulator is to use a computer to simulate, as closely as possible, the actual downhole events that occur while performing a fracturing treatment. Simulation allows design iterations, if necessary, to optimize the treatment design before starting expensive field operations. Previously, using a simulator to model tip-screenout designs, such as those of FracPac Completion Services, was a formidable task. Early simulators had to be modified to account for the significant amounts of proppant that could be placed after the initiation of a tip screenout and the higher proppant concentrations and higher conductivities that resulted from this type of treatment. A number of reliable fracture design simulators are currently available for tipscreenout-design fracturing treatments. The following discussion focuses on three of the major programs that perform tip-screenout fracturing design.

FRACPAC The FRACPAC program has been developed by Halliburton to assist in the design of tip-screenout fracturing treatments. The 3-D fracture geometry predictions from the XTENT program are incorporated with a modification to FRACPAC that allows pumping to continue after the tip screenout initiates. Upon tip-screenout initiation, fracture length extension and fracture height extension stop and injection of additional slurry causes fracture width to grow. Calculations for fluid loss, fracture width, proppant concentration, and net treating pressure during pumping

continue after tip-screenout initiation. Treatment modeling ends when the user-specified increase in net treating pressure is reached. The FRACPAC design simulator offers some very good input options such as the capability of reading dynamic in-situ rock stress measurements directly from wireline logging files. The program also has limitations, especially in complex reservoirs. FRACPAC allows only one pay zone to be analyzed, and even then the stress values across the zone are averaged. Values for fluid loss are also limited. Only two values are allowed for fluid loss: one value for the pay interval and the other for outside the pay interval. In wells where several highpermeability intervals are separated by small layers of shale, FRACPAC requires the user to make assumptions that can cause the software to be difficult to use.

Fracture Design Simulators

STIMPLAN The STIMPLAN program, developed by NSI Inc., is a fracture design simulator with special modifications that allow for tip-screenout designs. At tip-screenout initiation, fracture extension is stopped and the program calculates a width increase based on the increase in the net treating pressure. This program will analyze complex formations composed of multiple productive layers with varying fluid-loss coefficients. STIMPLAN is welldesigned, easy to use, and is a popular choice among the professionals who need an effective tool for designing fracturing treatments for highpermeability formations.

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FRACPAC COMPLETION SERVICES FRACPRO The FRACPRO program was developed by Resources Engineering Systems, Inc. (RES) with support from the Gas Research Institute (GRI). This fracture design model goes beyond standard simulators by acquiring real-time fracturing data during treatment. The program can be used to design fracturing treatments and then acquire downhole data during field operations or from a treatment database to confirm design estimates or perform detailed posttreatment analysis. Changes to the design and, if necessary, the treatment can be made to better match job data to design criteria. The capabilities of both designing, monitoring, and analyzing the fracturing treatment make FRACPRO a versatile model for both minifrac analysis and fracture design. The FRACPRO model can analyze several layers of formation with varying rock properties and fluid-loss coefficients. Also, the model allows the user to select either wall-building or nonwall-building fracturing fluids to be used for the treatment. This fluid selection feature is important, since both of these fluid types (HEC and borate-crosslinked fluids) are used in high-permeability formations. HEC does not build a filter cake and is controlled by viscous invasion of the formation, whereas borate-crosslinked fluids simulate a wall-building fluid with high spurt volumes. Multiple fluid designs can be handled with changing fluidloss coefficients and different fluid-loss characteristics of the fracturing fluids. This feature is helpful when, for example, a fracturing schedule is designed that calls for a borate-crosslinked pad volume followed by a linear HEC gel used to place the proppant.

RECOMMENDATIONS Even more important than the selection of a particular fracture-design program is consistency throughout the design of a fracturing treatment. The model used to analyze the minifrac test should also be used to design the main fracturing treatment. Failure to be consistent with fracture design software will almost always cause design errors due to different geometry assumptions made in different programs. For the design of fracturing treatments in high-permeability formations, a 2-D fracture simulator should not be used. A 2-D simulator can cause errors in the final fracturing design by requiring many geometric assumptions on the part of the user. Halliburton strongly recommends the use of one of the three programs discussed and that the design and analysis of minifrac tests and the main fracturing schedule be implemented on the same software package.

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Chapter 8

INTRODUCTION Minifrac testing is performed before a fracture stimulation to determine the leakoff characteristics of the formation and the selected fracturing fluid. Determining leakoff characteristics is especially critical when designing a tipscreenout fracturing treatment such as FracPac Completion Services since fluid leakoff is critical in determining when and where the tip screenout occurs. The high-permeability formations that FracPac completions are designed for show wide variations in fluid efficiency. A successful FracPac treatment requires the creation of a highly conductive, wide fracture of adequate length. Such fractures are best achieved through initiating a tip screenout at the desired distance from the wellbore, which reduces the acceptable margin of error in estimating the fluid-loss coefficient. Short pumping times are characteristic of FracPac treatments and further reduce the error margins by not allowing time to correct for errors in the fluid leakoff estimates. Underestimating or overestimating the fluid leakoff can lead to either a premature screenout or completion of the treatment without achieving a tip screenout. Both premature screenout and a lack of a screenout do not achieve the design requirements for length or conductivity and are equally undesirable. Therefore, performing and successfully analyzing a minifrac test before the main treatment is especially important for FracPac applications.

SPECIAL CONCERNS OF HIGH-PERMEABILITY FORMATIONS

by a large spurt volume that is lost before a filter cake builds up on the wall of the fracture. The permeability of the formation greatly affects the spurt volume which may account for 60% to 90% of the total fluid loss during the treatment.

Minifrac Analysis

If fracturing fluids such as hydroxyethylcellulose (HEC) gels are used in highpermeability formations, a filter cake is not formed on the formation wall. Fluid leakoff behavior of HEC gels is governed by non-Newtonian viscous invasion of the fluid into the porous matrix and does not follow the standard ti me function of wall-building gels. Fluidloss behavior of such gels cannot be accurately modeled using a single fluidloss coefficient, and severe errors in treatment design can result from using such coefficients.

Current Recommendations Halliburton strongly recommends performance of a minifrac analysis before conducting a fracturing treatment in high-permeability formations. The fluid efficiency and fluid leakoff coefficients in high-permeability formations (greater than 20 md) are not only extremely sensitive to the average permeability of the formation to be treated but also to the permeability distribution and the treating pressure. Therefore, the fluid leakoff coefficients of the zone of interest should be identified. Designing a FracPac treatment does not allow the building of any safety factors in the form of using additional pad volume since the additional fluid may prevent the onset of the tip screenout and subsequent packing of the fracture.

The fluid loss that occurs in high-permeability formations is often dominated

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The current techniques for analyzing minifracs have several assumptions that are valid for low-permeability formations but lead to oversimplifications in highpermeability formations. Until more accurate techniques are developed to analyze minifracs in high-permeability formations, conventional analysis techniques should be used with the understanding that they may result in significant errors in fluid leakoff characterization.

Live Annulus Pressure (psi)

Pressure Decline 1,000 800 600 400 70-lb/Mgal HEC at 125°F

200 0 0

1 2 Square Root of Time ( min )

3

Figure 8.1 — This pressure-decline curve is plotted versus the square root of time. The fracture closed in just under 1 minute in the test performed.

G-Function Plot

Pressure (psi)

1,000 800 70-lb/Mgal HEC at 125°F

600 400

1.0

1.2 1.4 1.6 1.8 G-Function (dimensionless)

2.0

Figure 8.2 — Pressure (pressure decline) can also be plotted versus the G-function (dimensionless).

Horner Plot Analysis 3,000 Bottomhole Pressure (psi)

High-permeability formations tend to have lower net pressures and shorter closure times as opposed to lowpermeability formations. Closure times of 1 minute or less are common. Correctly determining closure pressure and closure time is more difficult in high-permeability formations and is also more critical to designing an effective fracturing treatment. A major concern of analyzing minifrac tests in high-permeability formations is the nature of the fluid loss. The manner in which the pressure decline is analyzed depends on the type of fluid (linear gel or crosslinked fluid) that is used in the minifrac.

200 0

2,800 2,600 2,400 2,200 2,000 1,800 1

10 Horner Time Log ((tp+dt)/dt)

100

Figure 8.3 — The data from Figure 8.1 and Figure 8.2 can be plotted on a Horner plot.

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Analysis of Pressure Decline by Determining Closure Pressure and Closure Time

Linear gels such as HEC do not build up a filter cake on the fracture face, while crosslinked fluids may be associated with high spurt-loss volumes. Assumptions that the spurt-loss characteristics of a formation are negligible, instantaneous, or do not affect the pressure decline have been made while analyzing tests in low-permeability formations. In high-permeability formations, however, spurt times can be as long as the fracture closure times, and the spurt volume can account for 40% to 90% of the fluid loss of the treatment. A conventional technique for analyzing minifrac tests is currently being utilized for high-permeability applications such as FracPac treatments. This method plots the shutin pressure versus the square root of time, or the shut-in pressure versus the G-function. The straight-line deviation determines the closure time and closure pressure. The G-function or the ti me plot should only be used to identify fracture closure as accurately as possible. Using a single fluid-loss coefficient (Ceff ) determined from the slope of the G-function plot can lead to severe errors in treatment design. The errors are due to the differing leakoff characteristics of the linear and crosslinked fluids. Crosslinked fluid behavior deviates significantly from the assumptions made by using a single fluid-loss coefficient.

A Horner plot can be used to help confirm closure pressure. In the Horner plot, pressure is plotted against Horner time (dimensionless) as shown in Figure 8.3. The linear portion of the graph indicates pseudoradial flow, thus implying fracture closure. The deviation from the straight line can yield the closure time and pressure. The use of this method for all types of formations is inconclusive since an insufficient amount of data exists to prove the validity of this approach. However, the use of the Horner plot in conjunction with the pressure-versus ti me plot may provide useful information. When HEC fluids or other linear gels are used without fluid-loss additives, the pressure-decline curve must be analyzed with care since leakoff behavior is highly pressure dependent. Current minifrac analysis methods are also insufficient for crosslinked fluids, and new analysis methods are under development.

Determining Fluid Efficiency and FluidLoss Coefficients Until more accurate analysis techniques are developed for all fracturing fluids, conventional techniques should be used to determine closure pressure and closure time. To effectively design a tip screenout, the fracture design model should also be used to analyze the minifrac test. The following procedure is suggested: 1. Use the fracture design model to simulate the minifrac. Adjust the appropriate input parameters to match the net pressure during the entire pumping treatment or at least at the instantaneous shut-in pressure (ISIP). Match the time for the fracture to close. 2. Most reservoirs require adjustments to fluid loss (or permeability) and stress inputs. Use the information in the following section as a guide to select the proper fluid-loss properties for modeling. Using incorrect fluid properties when performing a minifrac analysis in high-permeability formation can result in large errors. Such errors can also occur when using incorrect fluid properties or if the job size is changed. Based on data from current laboratory testing, the following procedures are recommended for the various types of fracturing fluids.

Cw and Spurt - Fluid Loss Match 6 Volume/Area (gal/ft2)

Figure 8.1 and 8.2 show a typical pressure decline for an HEC gel versus ti m e plot and as a conventional Gfunction plot, respectively. The fracture closed in just under 1 minute which made it difficult to analyze these data.

Cvc

4 Cw

2

Vol

0 0

2 4 Square Root of Time ( min )

6

Figure 8.4 — In fracture design models that require a Cw and spurt or a Ceff value, the Cw spurt option should be used. Built-in calculations of the design simulator account for the effects of reservoir-fluid viscosity and compressibility on fluid loss, while adjusting only fracturing-fluid effects. Fluid-loss options such as Ceff that override built-in reservoir calculations should not be used. Linear gels can be modeled as power-law fluids. Fluid loss is controlled by the viscous invasion into the formation and by reservoir compressibility (CVC ).

The results of a series of dynamic fluid-loss tests performed in many different permeabilities shows that while Cw remains fairly constant, the spurt volume changes dramatically as the permeability increases. Therefore, for boratecrosslinked fluids, the book value for Cw should be used. The spurt volume should be adjusted until a match is achieved. Refer to Figure 8.4 for the results of fluid-loss tests on borate-crosslinked fluids. The subsequent design should then be completed using both a spurt volume and Cw .

Linear Fluids With an appropriate viscosity for the leaked-off fluid, this option can be used for fracture design models that have a nonwall-building fluid. With fracture design models that require Cw and spurt or a Ceff value, the Cw-Spurt option should be used. The recommended procedure is to match a Cw and spurt to the fluid loss calculated from Equation 9.1 in Chapter 9, Appendix A. If this does not result in a match with the observed closure time and pressure, the permeability of the formation must be changed, and a new value for spurt volume and Cw should be estimated. This is an iterative procedure that can be time-consuming but can be performed by using a spreadsheet. Some Cw and spurt volumes that provide a best data fit for the minifrac

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analysis may not be the best values for the main fracturing treatment if the job sizes are significantly different. Refer to Figure 8.4 for an example of this technique. This analytical procedure allows the built-in calculations of the fracture design simulator to account for the effects of reservoir-fluid viscosity and compressibility on fluid loss, while adjusting only fracturing-fluid effects. Fluid-loss options that override these reservoir-based calculations (such as Ceff ) should not be used.

Fluid Loss of Linear Gels When a linear gel is used in high-permeability formations (greater that 20 md), the fluid does not form a filter cake at the formation wall unless fluid-loss additives are used. If a linear gel is used, the fluid loss is controlled by the viscous invasion of the fluid into the formation and the reservoir compressibility (CVC ). The rheological properties of most linear gels allow them to be modeled as powerlaw fluids. Leakoff is described by

n′

60t (8.1)

NOMENCLATURE = porosity

810 15k

n′ + 1

Fluid-loss test results indicate that fluid loss in highpermeability formations is characterized by filter-cake buildup and high spurt loss. Thus, conventional minifrac testing and analysis may not be sufficient to predict fluid loss. The insufficiency comes from the calculation of only a single fluid-loss coefficient (Ceff ). Corrections for the spurt loss can be made if the value is determined from laboratory data, but this method is an approximation. The spurt volume is a function of several formation variables and a better value can be determined from field data. A method has been developed to calculate both the Cw and average spurt loss (Vsp ) using a dual pump-in and shut-in technique. This technique should be used, whenever possible, to calculate these important variables and ultimately achieve a more efficient fracture treatment design.

= rock factor

n′ 1 n′ 1 72p n′ + 1 n′ + 1 V 3n′ 1 K ′

Fluid Loss of Crosslinked Fluids

.............................

p = pressure drop (psi) k = permeability (md) K′ = consistency index (lbf - secn/ft2 ) n′ = flow behavior index t = time (min)

or n′

n ′ + 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (8.2) V vt

where V is leakoff volume per unit area (m3/m2), n′ is flow behavior index, K′ is consistency index (lbf secn/ft2), is rock factor, p is pressure drop (psi), k is permeability (md), is porosity, and t is time (min). These equations give a leakoff profile characterized by Figure 8.4. Conventional models may be inaccurate for linear gels since they assume that the leakoff volume is proportional to the ti m e.

80

V = leakoff volume per unit area (m3/m2 ) Ceff = overall fluid-loss coefficient Cw = filter-cake coefficient Cvc = reservoir compressibility Vsp = average spurt loss

Chapter 9

INTRODUCTION The proper selection of fracturing fluid is one of the most critical elements in FracPac Completion Services design. To select the proper fluid, concerns such as fluid-loss control, fracture conductivity, formation damage, and proppant transport must be considered. Extensive testing has been conducted to promote better understanding of fracturing-fluid behavior in treatments of high-permeability formations. In these tests, the fluids were evaluated for fluid-loss properties, regained permeability (formation damage), and fracture conductivity. The results from these tests have proven very helpful in making the best fluid selection for a given well. The first portion of this chapter focuses on Halliburton’s recommendations for fracturing fluids based on test data. Later in the chapter, types of fluid systems, additives, and the general behavior of these fluid systems is discussed. Appendices present the models used to characterize the fluids and quality assurance measures that can be applied to make FracPac most effective.

CONCLUSIONS AND RECOMMENDATIONS The results from formation-damage tests and fracture-conductivity tests 1, 2 have shown hydroxyethyl cellulose (HEC) to be the most applicable linear gel for FracPac treatments. Borate-crosslinked hydroxypropyl guar (HPG) gels were found to be the most effective crosslinked fluid system for FracPac Completion Services. The use of either a linear gel or a crosslinked gel is very dependent on the formation permeability,

reservoir fluid, and reservoir pressure of the candidate well. Table 9.1 summarizes the fluids and conditions that were tested to develop the fluid-selection criteria for FracPac applications. Figure 9.1 shows the recommended fluids for different formations based on permeability and reservoir type.

Fracturing Fluid Systems

Formation damage and fracture conductivity studies have shown that breakers should be in solution when fracturing high-permeability formations so that the entire crosslinked gel volume that leaks off into the formation can be effectively broken. Fracture conductivity can be enhanced if an encapsulated breaker is placed in the proppant pack. Some unique well conditions may require the use of fluid systems that are different from the HEC linear gel and borate-crosslinked HPG gel prescribed previously as most applicable to all FracPac procedures. For this reason a complete summary of all the fluid systems tested and the properties of each are discussed in the following sections.

AVAILABLE FLUID SYSTEMS As many as 50 different fluids have been developed to solve various needs within the oil- and gas-well stimulation and completion markets.3- 21 The major types of fluids that remain at the backbone of the industry are as follows: • Conventional linear gels • Borate-crosslinked fluids • Organometallic-crosslinked fluids • Aluminum phosphate-ester oil gels

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Table 9.1 — Fracturing Fluids Evaluated in the Study Fluid System

Temperature (°F)

70-lb HEC

120

1-lb SP/Activator

70-lb HEC/40-lb Silica Flour

120

1-lb SP/Activator

30-lb HPG/Borate

120

1-lb SP/Activator

Gelled Oil System

120

NONE

70-lb HEC

180

0.2-lb SP


180

0.2-lb SP

70-lb HEC

180

0.75-lb SP

70-lb guar

180

0.2-lb SP

40-lb HPG/Titanate

180

0.2-lb SP

40-lb HPG/Borate

180

0.2-lb SP

40-lb CMHPG/Zirconate

180

0.75-lb SP

40-lb CMHEC/Zirconate

180

0.4-lb SP

40-lb HPG/Titanate

240

NONE

40-lb HEC/Borate

240

NONE

All of these fluids may be run as two-phase systems, since they all are compatible with nitrogen. However, only the linear gels and some of the organometallic-crosslinked fluids are compatible with carbon dioxide. A brief description of each of the fluid systems listed above and how they can be applied in high-permeability fracturing treatments is included in the following sections.

Conventional Linear Gels Conventional linear gels are very simple to use and can be formulated with a wide array of different polymers and fluids. Common polymer sources used with the linear gels are guar, HPG, HEC, carboxymethylhydroxypropyl guar (CMHPG), and carboxymethylhydroxyethyl cellulose (CMHEC). Previous studies performed with these fluids have indicated that gel residue from guar fluids can be as high as 8% to 10% by weight. The high residue content of guar gels can cause permeability reduction in the proppant pack of the fracture, if further cleanup measures are not applied. 22,23 Similar problems have been observed with linear HPG and CMHPG, though the resultant damage is not as extreme with this type of fluid system. In both HPG and

82

Breaker Concentration

CMHPG fluids, the residue content can be from 1% to 3% by weight. HEC fluid sytems are virtually residue free and provide the best proppant-pack permeability. The general characteristics of linear gels are poor proppant transport and low fluid viscosity. In lower-permeability formations (less than 0.1 md), linear gels control fluid loss very well, whereas in higher-permeability formations fluid loss can be excessive. Linear gels tend to form thick filter cakes on the face of lower-permeability formations, which can adversely affect fracture conductivity. The performance of linear gels in higher-permeability formations is just the opposite, since it forms no filter cake on the formation wall. Much higher volumes of fluid are lost due to viscous invasion of the gel into the formation. Fracture conductivity can be much higher when linear gels such as HEC are used. New biopolymer gel systems have been recently added to the selection of gravel pack fluids. These biopolymer systems offer interesting properties for FracPac applications also. These fluids feature clean, controllable breaks that result in excellent regained permeability and fracture conductivity. The new biopolymer systems that have been tested to date2 have had restricted use in FracPac treatments because of their high cost and unfavorable shear-thinning properties.

Borate-Crosslinked Fluids 700 600

Permeability (md)

Borate-crosslinked fluids were once restricted from hightemperature applications, but advances have improved them for use in temperatures to 300°F.24, 6, 7 The polymers most often used in these fluids are guar and HPG. The crosslink obtained by using borate is reversible and is triggered by altering the pH of the fluid system. The reversible characteristic of the crosslink in borate fluids helps them clean up more effectively, resulting in good regained permeability and conductivity. In addition to good cleanup properties, with the proper composition, borate fluids provide good proppant transport, stable fluid rheology, and low fluid loss. The use of boratecrosslinked fluids has increased significantly over the last decade, and HPG-borates show great potential for highpermeability applications.

500 400 300 200 100 0

Oil

Gas

Organometallic-Crosslinked Fluids Organometallic-crosslinked fluids have long been the most popular class of fracturing fluids. Primary fluids that are widely used are titanate and zirconate complexes of guar, HPG, CMHPG, or CMHEC. These fluids are extremely stable at high temperatures and are currently the only type of fluids that can be used at bottomhole temperatures that exceed 300°F. The proppant transport capabilities of organometalliccrosslinked fluids are excellent, and these fluids form a very resilient filter cake on the face of the fracture. The metallic bonds which form the crosslink mechanism in these fluids are not reversible and do not break when exposed to conventional gel-breaking systems. Because of the strong bonds of these fluids, the filter cakes deposited on the fracture face can be more difficult to clean up and can result in impaired fracture conductivity. Cleanup difficulty is the major disadvantage to these types of fracturing fluids; thus, their use in high-permeability formations is a questionable practice. When carbon dioxide is used or when dealing with high reservoir temperatures, organometallic-crosslinked fluids may be necessary despite cleanup difficulties.

HEC

Formation Dependent

Borate (HPG)

Figure 9.1 — Formation type and permeability play a major role in fracturing fluid selection. Fluid recommendations are shown based on formation permeability for both oil and gas reservoirs.

there are greater concerns regarding personnel safety and environmental impact, as compared to most water-fluids. In wells with high-permeability formations, the advantages of using gelled oils can outweigh their disadvantages, if safety and environmental issues can be resolved.

Foamed and Other Fluids Other fluids such as polymer-emulsion systems and gasenergized systems exist, but they have limited application in high-permeability formations due to environmental, safety, or equipment limitations. Foamed or energized fluids may be especially useful for FracPac treatments of highpermeability formations in low-pressure gas reservoirs.

Aluminum Phospate-Ester Oil Gels Gelled oil systems were the first high-viscosity fluids used in hydraulic fracturing operations. A major advantage to this type of fluid is its compatibility with almost any formation type. There are some disadvantages in using gelled oils. Gelling problems can occur when using crude oils and the cost of using refined oils is very high. Also

BREAKERS For high-permeability fracturing applications, use of the proper gel breaker system is crucial to realizing maximum regained permeability and fracture conductivity. In lowpermeability applications, the use of delayed, encapsulated breakers has proven very effective in breaking the filter

83


High-permeability treatments require the use of breakers which are in solution with the gel systems, so that even the gel which leaks off into the formation is completely broken at the proper time. Halliburton still recommends that additional encapsulated breaker be mixed into the proppant-bearing stages of the treatment. This helps ensure that an adequate amount of breaker is present to break the filter cake on the fracture face and thus maximizes fracture conductivity.

Filtrate Volume Per Area (ml/cm2)

Fluid Loss at 120°F 15 70-lb HEC / 40-lb Silica Flour

10 Gelled Oil System

70-lb HEC

5 30-lb HPG / Borate

0 0

1

2

3 4 5 6 7 Square Root of Time ( min)

8

9

Figure 9.2 — Selection of the proper treatment fluid is the most effective means of controlling fluid loss in high-permeability formations. The borate-crosslinked fluids have proven themselves superior in high-permeability formations, both with high fluidloss efficiency and easy cleanup.

cake on the formation face and maximizing fracture conductivity. High-permeability applications, however, result in the invasion of a viscous gel into the formation and pose the additional concerns which follow: • Encapsulated breakers “plate out” on the fracture face or stay in the proppant bed, which helps break the filter cake and gel in the proppant pack. This type of breaker does not help break the gel that enters the formation. • The damage caused by viscous invasion of the gel can be serious if the gel remains unbroken in the formation. A reduction in regained permeability is the first potential source of formation damage, since the unbroken gel blocks the pore spaces in the formation. A second potential source of damage can be caused by the flow of unbroken gel from the formation into the proppant pack, which can reduce fracture conductivity. • Cleanup time can be drastically increased, sometimes requiring several days or weeks to recover the load fluid from the fracturing treatment. Producing the well at higher drawdown pressure is sometimes attempted to speed up the load-fluid recovery. These higher drawdown pressures can apply additional stress to the formation and result in early sand production, which negates the effect of the fracturing treatment.

84

Break testing should be performed before the job is pumped. These tests help ensure that break times are sufficient to place the treatment, but short enough to allow the well to be put on production and cleaned up in a reasonable amount of time. The breaker schedule should provide good fluid properties for twice the anticipated pump time and a complete break in 2 to 4 hours. Halliburton has tested a new procedure in which a dual fluid system is pumped. In this procedure, a high-efficiency pad volume is pumped, followed by a low-efficiency proppant placement fluid. This dual-stage approach is designed to more effectively place proppant into the created fracture, particularly in very high-permeability formations where it may not be possible to create adequate geometry with a linear gel. Test results have indicated that the fluid used to place the proppant can be chosen so that it will effectively break the filter cake of the pad fluid and greatly increase the fluid leakoff rate. Proper fluid selection makes it possible to control the amount of fluid loss while pumping the pad volume, thus allowing the desired fracture length and width to be created using smaller pad volumes. For example, using a borate-crosslinked fluid system improves the fluid-loss control and increases the fluid efficiency of the pad volume. Following the borate system with a pH-buffered HEC for proppant placement will help reverse the filter cake formed by the borate fluid and break the crosslink of the borate gel that leaked off into the formation. There are several benefits to this approach. Overall, less fluid is required to be pumped, minimizing potential formation damage. The linear HEC gel within the proppant bed provides maximum fracture conductivity. This dual-fluid technique, if applied with a well-designed breaker schedule, can result in reduced formation damage and maximum fracture conductivity. This technique allows the use of HEC as well as other gelling agents for the linear gel stage. The same benefits can be obtained by using the borate-crosslinker and buffering the base gel.

FLUID LOSS

Fluid-loss testing has shown that crosslinked fluids are far superior to linear gel systems for reducing fluid loss in highpermeability formations. Comparison of fluid loss using crosslinked gels shows that the borate-crosslinked fluids are particularly more efficient than any of the organometallic systems tested. The high fluid-loss efficiency of the borate fluids, plus the advantages of their reversible crosslink and their easy cleanup, has made them the preferred choice for crosslinked gels. Based on these test results and on field results, borate-crosslinked fluids are highly recommended in high-permeability wells where HEC performs poorly. Viscous fluid invasion predominantly controls fluid loss in high-permeability formations more so than in conventional fracturing in low-permeability formations. As a result of this fluid-loss behavior, the performance of linear gels and crosslinked gels is very different and is discussed in detail in the following sections.

Linear HEC Fluids In formations with permeability that exceeds 20 md, the fluid-loss behavior of linear HEC gel systems is completely governed by the invasion of the whole gel into the formation. A filter cake does not build up on the faces of the fracture, and the leakoff rate is controlled by the rheological behavior of the gel in the porous medium. HEC gels have been observed to behave as power-law fluids in high-permeability formations. A plot of the measured apparent viscosity versus shear rate in a test core for an HEC fluid system is shown in Figure 9.3. A model for the leakoff of a power-law fluid was developed based on test results and appears in Appendix A at the end of this chapter. The non-Newtonian power-law nature of fluid leakoff in high-permeability formations has led to some interesting insights into its fluid leakoff behavior. One consequence of using non-Newtonian fluids is that their leakoff can

100

Berea Sandstone, Rock Factor = 0.577

Apparent Viscosity (cp)

Dynamic fluid-loss studies performed on high-permeability cores 1,2,21,33 have provided very useful information about fluid-loss properties as a function of gel type and formation properties. These test results have indicated that in highpermeability rock, selection of a proper treatment fluid is the most effective means of controlling fluid loss. In most cases, the use of a particulate-type fluid-loss additive can improve the fluid loss to the formation; however, these types of additives can damage fracture conductivity during production (Figure 9.2).

HEC Gel Apparent Viscosity vs. Shear Rate

Berea Sandstone, Rock Factor = 0.659 Viscometer data

10 100

1,000 Shear Rate (1/s)

10,000

Figure 9.3 — A plot of apparent viscosity versus shear rate for an HEC fluid shows that these gels behave as power-law fluids in high-permeability formations.

decrease faster over time than that of a Newtonian fluid. As a non-Newtonian fluid invades the formation rock, the shear rate inside the porous media is very high, typically about 10,000/sec. As the depth of fluid invasion increases, the filtrate rate decreases as does the shear rate within the rock. The fluid’s apparent viscosity increases with the decreasing shear rate due to the fluid’s shear-thinning nature. The increase in apparent viscosity aids in controlling fluid leakoff. This fluid behavior also implies that high-permeability treatments with linear gels should have higher fluid efficiencies than predicted with a single value of CVC and that using fluids that are highly nonNewtonian in nature (lower values of n ′) may provide lower fluid efficiency.

Guar-Based Linear Gels Some guar-based gels such as HPG show the same nonwall-building characteristics as HEC fluids in high permeability. However, guar gel tends to build a filter cake, and most tend to develop a better filter cake than the HEC fluids. This wall-building tendency has a complex leakoff function that is initially governed by viscous invasion of a non-Newtonian fluid and then changes over time to a system dominated by filter cake. This tendency to develop a filter cake with guar fluids is believed to be due to the high residue content of this fluid as compared to HEC. The filter-cake buildup and the deeper formation damage makes guar unsuitable for FracPac applications. HPG and CMHPG are usable FracPac fluids due to their lower gel-residue content. These fluids, however, do not perform as well as HEC.

85


Table 9.2 — Fluid Loss Results Core Perm

Invasion

Vspt

Cw

Temp

(ft/m in )

(°F)

Fluid

(md)

Depth (in.)

(gal/ft2)


191

3

2.970

0.00328

120

170 - 420

1.1

0.404

0.00223

120

Gelled Oil System

200

3.1 & 5.1

1.060

0.01181

120

70-lb HEC

6.45

6

0.790

0.00492

180

70-lb guar

30-lb HPG/Borate

120

5

0.500

0.00115

180


400

6

5.290

0.00492

180

40-lb HPG/Borate

7.9

3.1

0.110

0.00164

180

40-lb HPG/Borate

170 - 230

1.1

0.077

0.00279

180

40-lb HPG/Borate

1,100

1.1

0.559

0.00295

180

40-lb HPG/Titanate

452

3.1

0.837

0.00230

180


380

3.1

0.677

0.00459

180


380

1.1

0.383

0.00197

180

40-lb HPG/Borate

184

3.1

0.392

0.00262

240

40-lb HPG/Titanate

125

3.1

0.736

0.00295

240

Fluid Loss at 240°F Filtrate Volume Per Area (mL/cm2)

25 70-lb HEC /40-lb Silica Flour

20 15

70-lb HEC

40-lb CMHPG / Zirconate

)

Filtrate Volume Per Area (mL/cm2

Fluid Loss at 180°F

40-lb HPG / Titanate

10

40-lb CMHEC / Zirconate 40-lb HPG / Borate

5 0 0

5

10 15 20 Square Root of Time ( min)

25

Figure 9.4 — The filtrate volume data from fluid-loss tests made at 180°F were plotted. Tests of all the fluids were run on Berea sandstone cores.

86

5 40-lb HPG /Titanate

4 3

0 2

40-lb HPG /Borate

1

0

1

2 3 4 5 6 Square Root of Time ( min)

7

Figure 9.5 — The filtrate volume data from fluid-loss tests made at 240°F were plotted. Tests of all the fluids were run on Berea sandstone cores.

8

A very important factor about this type of fracturing fluid system is that although the results of fluid-loss tests have followed the classical models of spurt loss followed by filter-cake formation, very high spurt volumes and long spurt times are observed in high-permeability cores. All observations suggest that even with the high viscosity of crosslinked fluid systems, the early leakoff rate is primarily governed by viscous invasion of the gel into the formation. The depth of formation invasion and the amount of time required to build a filter cake appears to be a complex function of the formation permeability, fluid viscosity, and differential pressure. Crosslinked gels do not invade the formation as deeply as linear gels, but they do develop a very concentrated buildup in the formation near the fracture face, which can be very difficult to clean up. Viscous invasion of the formation by crosslinked fluids has been observed to govern fluid loss until a filter-cake formation occurs. Compared to linear gels, the higher viscosity crosslinked fluids consistently have shown lower fluid loss and shallower invasion of filtrate into the cores tested. Classical fluid-loss models can be used to model the leakoff of crosslinked fluids in high-permeability formations, but the early spurt volumes are very significant and should not be ignored when designing a fracturing treatment. Fluid-loss test results are summarized in Table 9.2. Test data are shown in Figure 9.4 through Figure 9.6.

Volume Per Area (ml/cm2)

Crosslinked fluid systems that were tested showed filter cake formation and followed the more classical ti m e models for fluid loss. (Refer to Appendix A at the end of this chapter for models of fluid behavior.)

500

5 Volume Per Area

4

400 300

3 Region 1

2

200

Region 2 Region 3

100

1

0

0 0

1 2 3 4 5 6 7 Square Root of Leakoff Time ( min)

8

Pressure Drop Per Length (psi/cm)

HPG/ Titanate Gel Filtrate Volume vs. Pressure Drop

Crosslinked Fluid Systems

Figure 9.6 — The filtrate volume and the pressure drop across the first three zones of the core were measured during the fluidloss test. The test was performed with 40-lb HPG/Mgal+Titanate at 180°F in Berea sandstone.

FORMATION DAMAGE The fluid-loss test results discussed previously indicate that fracturing fluids behave very differently in high-permeability formations than in low-permeability formations. The viscous invasion of the gels into the formation is a significant variation from behavior in conventional, lowpermeability formations and has been investigated. A multiport Hassler sleeve was used as a laboratory tool to monitor the depth of invasion during static fluid-loss tests. The flow was then reversed through the sleeve (and the core being tested) to evaluate the regained permeability at various regions of the core as shown in Figure 9.7. These

Core Configuration

Perm Direction

2.1 cm

5.1 cm

5.1 cm

2.8 cm

Region 4

Region 3

Region 2

Region 1

Fluid Loss Direction

Distance = 15.1 cm

Figure 9.7 — The cores used in the fluid-loss tests and the formation-damage tests were divided into the regions shown to measure the depth of formation damage. The fluid-loss direction and the permeability direction (which is the direction in which formation damage occurs) are exactly the opposite.

87


Table 9.3 — Formation Damage Results Overall Perm

Temp

(md)

Region

Regain

(°F)

70-lb HEC

230

1 2 3

31 28 30

120


191

1 2 3

26 40 39

120

30-lb HPG/Borate

420

1 2 3

18 43 55

120

Gelled Oil System

200

1 2 3

24 22 68

120

70-lb HEC

6.45

1 2 3

26 23 29

180

70-lb HEC

160

1 2 3

30 43 44

180

70-lb HEC

1200

1 2 3

47 57 37

180

70-lb HPG

159

1 2 3

3.6 9.8 19

180

70-lb guar

120

1 2 3

0.8 5.8 18

180


400

1 2 3

5 27 36

180

40-lb HPG/Borate

7.9

1 2 3

85 71 94

180

40-lb HPG/Borate

170

1 2 3

44 63 65

180

40-lb HPG/Borate

1100

1 2 3

1.9 88 91

180

40-lb HPG/Titanate

452

1 2 3

0.1 0.2 8.8

180


380

1 2 3

4 76 62

180


380

1 2 3

13 14 42

180

40-lb HPC/Borate

184

1 2 3

74 44 59

240

40-lb HPG/Titanate

125

1 2 3

3.1 5.1 45

240

Fluid Type

88

Percentage

Table 9.4 — Fracture Conductivity Results (md-ft) Temp Fluid

Core Type

2,000 psi

4,000 psi

(°F)

70-lb HEC

Berea

6,685

2,875

120


Berea

4,516

1,869

120

30-lb HPG/Borate

Berea

5,128

2,167

120

Gelled Oil System

Berea

4,527

2,579

120

70-lb HEC

Texas Creme

5,939

1,537

180

70-lb HEC

Berea

6,516

2,891

180

70-lb HEC

Brown

7,239

3,112

180

70-lb HPG

Berea

3,154

922

180

70-lb guar

Berea

559

176

180


Berea

4,302

1,423

180

40-lb HPG/Borate

Texas Creme

3,235

1,045

180

40-lb HPG/Borate

Berea

2,441

757

180

40-lb HPG/Borate

Brown

3,740

1,358

180

40-lb HPG/Titanate

Berea

3,446

1,046

180


Berea

1,626

519

180


Berea

941

611

180

40-lb HPG/Mgal + Titanate

Berea

3,162

845

240

40-lb HPG/Mgal + Borate

Berea

573

260

240

formation-damage tests (to determine regained permeability) were conducted at several different temperatures with selected fluids. Results of these tests are listed in Table 9.3.

• Temperature limitations of HEC restrict its use to temperatures less than 180°F, while borate-crosslinked fluids remain effective up to 300°F.

Formation-damage test results were very consistent and show HEC and borate-crosslinked gels to cause the least amount of damage. Although core invasion was very deep with the HEC fluid, the very low residue content of this fluid allows it to flow back very efficiently. The linear guar-based gels show deep invasion and high residue content; the combination of these factors causes severe formation damage. Crosslinked gel systems, in general, show much less depth of invasion. Using the boratecrosslinked fluids, with their high viscosity, results in less invasion than use of organometallic fluid systems. Also, the borate fluids clean up much more easily than the organometallic fluids, and give overall better results in high-permeability formations.

• HEC shows low damage to high-permeability formations. Borate-crosslinked gels show less permeability recovery than do HEC fluids.

Based on the results of the formation-damage studies, the following general observations and recommendations were made:

• Depth of invasion for HEC can be great due to poor fluid-loss control and some deeper damage can result. Invasion depths from using borate-crosslinked fluids in high-permeability formations are significant and can cause increased formation damage near the fracture face. • The importance of an effective in-solution breaker system is readily evident when evaluating formation damage. Improved cleanup of gels can be obtained in almost all situations if a more complete breaking of the gel occurs within the formation matrix. The dual-fluids approach to fluid-loss control can help manage more efficient break and cleanup.

89


• In fracturing applications, a greater degree of formation damage can be tolerated than in gravel-pack applications. In most cases, production simulator results have indicated that good regained permeabilities (in excess of 15%) will provide excellent results. This observation favors the borate-crosslinked fluid systems in high-permeability formations since they provide better fluid-loss control combined with acceptable levels of formation damage.

Sandstone acidizing procedures are sometimes used before, during, or after a gravel-pack treatment to help remove mobile fines and speed the cleanup of the load fluid. In some cases, formation conditions are not favorable for acidizing due to poor consolidation or incompatibilities with the fluids being pumped. Concerns about formation stability and compatibility should be addressed before completing the job.

FRACTURE CONDUCTIVITY

REFERENCES

Fracture conductivity testing was performed with the same selected fracturing fluids and core types and at the same temperatures as the fluid-loss and formation-damage tests. The results of fracture conductivity testing are listed in Table 9.4.

1.

Parker, M.A., Vitthal S., McGowen, J., Martch, E., Rahimi, A.: “Stimulation of High-Permeability Formations to Overcome Formation Damage,” Paper SPE 27378, 1994 Annual Symposium on Formation Damage,” Lafayette, Louisiana, February.

2.

McGowen, J.M., Vitthal, S., Parker, M.A., Rahimi, A., and Martch, W.E. Jr.: “Fluid Selection for High-Permeability Formations, “ Paper SPE 26559, 1993 SPE Annual Technical Conference, Houston, Texas, October 3-6.

3.

Penberthy, W.L. Jr., and Shaughnessy, C.M.: Sand Control, SPE Series on Special Topics, Volume 1, Richardson, Texas, (1992) 45-57.

4.

Schecter, R.S.: Oil Well Stimulation, Prentice-Hall, New Jersey (1992) 365-370, 571-573.

5.

Harms, W.M.: “Application of Chemistry in Oil and Gas Well Fracturing,” Oilfield Chemistry, Borchardt, J.K., and Yen, T.F. (eds.), American Chemical Society, Washington, D.C. (1989) 55-101.

6.

Ely, J.W.: “Fracturing Fluids and Additives,” Recent Advances in Hydraulic Fracturing, Gidley, J.L., Holditch, S.A., Nierode, D.E., and Veatch, R.W. Jr. (eds.) SPE Monograph Volume 12 (1989) 131-146.

7.

Gulbis, J.: “Fracturing Fluid Chemistry,” Economides, M.J., and Nolte, K.G.: Reservoir Stimulation, Prentice Hall, New Jersey (1989) 4-1 - 4-14.

8.

Sparlin, D.D., and Copeland, T.: “Pressure Packing with Concentrated Gravel Slurry,” Paper SPE 4033, 1972 SPE Annual Technical Conference, San Antonio, Texas.

9.

Sparlin, D.D.: “Sand and Gravel: A Study of Their Permeabilities,” Paper SPE 4772, 1974 SPE Symposium on Formation Damage Control, New Orleans, Louisiana.

HEC gels provided the best overall fracture conductivity. The results of this testing are somewhat conservative since the same fluids and in-solution breaker systems from the fluid-loss tests and the formation-damage tests were used. No delayed or encapsulated breakers were mixed with the proppant. Had these breakers been used, the performance of the crosslinked gels would have been greatly increased, resulting in better fracture conductivity. The fracture conductivity tests did show that under most conditions, the HEC and the borate-crosslinked gels outperformed all other fluids. When silica flour was used as a fluid-loss additive, it caused significant reductions in fracture conductivity.

GRAVEL-PACK COMPLETIONS Gravel packing is slightly different from FracPac completions since it does not involve tip-screenout fracturing. Gravel packing does, however, involve the near-wellbore region of the well and thus gravel-pack fluids must be kept very clean. All brines used in gravel-packing procedures should be filtered before being injected into the well. Gelled fluids should be sheared and filtered to remove any microgels that could damage the formation or the gravel-pack media. Formation damage is a primary concern in gravel-pack completions. To prevent formation damage, HEC, biopolymers, or clean brines are the preferred fluids for most gravel-pack completions. If heavy brines are required for well control, special gelling considerations are required to ensure adequate viscosity and stability. Specialty products are available for such applications.

90

10.

Scheuerman, R.F.: “Guidelines for Using HEC Polymers for Viscosifying Solids-Free Completion and Workover Brines,” JPT (February 1983) 306-314.

11.

Scheuerman, R.F.: “A New Look at Gravel-Pack Carrier Fluid,” SPEPE (January 1986) 9-16.

12.

Torrest, R.S.: “The Flow of Viscous Polymer Solutions for Gravel Packing Through Porous Media,” Paper SPE 11010, 1982 SPE Annual Technical Conference, New Orleans, Louisiana.

13.

Chauveteau, G., and Kohler, N.:” Influence of Microgels in Polysaccharide Solutions on their Flow Behavior Through Porous Media,” SPEJ, (1984) 361-368.

14.

Cole, C., Shah, S., Caveny, B., and Bellenger, B.: “Monitoring HEC Gel Shearing to Optimize Improvements,” Paper SPE 17480, 1988 SPE California Regional Meeting, Long Beach, California.

15.

Houchin, L.R., Hudson, L.W., Caothien, S. et al.: “Reducing Formation Damage through Two-Stage Polymer Filtration,” Paper SPE 15408, 1986 SPE Annual Technical Conference, New Orleans, Louisiana.

16.

Ashton, J.P., and Nix, C.A.: “Polymer Shear Mixer: A Device to Improving the Quality of Polymer Viscosified Brines,” Paper SPE 14829, 1986 SPE Symposium on Formation Damage Control, Lafayette, Louisiana.

17.

Penny, G.S.: “An Evaluation of the Effects of Environmental Conditions and Fracturing Fluids Upon the Long-Term Conductivity of Proppants,” Paper SPE 16900, 1987 SPE Annual Technical Conference, Dallas, Texas.

18.

Parker, M.A., and McDaniel, B.W.: “Fracturing Treatment Design Improved by Conductivity Measurements Under In-Situ Conditions,” Paper SPE 16901, 1987 SPE Annual Technical Conference, Dallas, Texas.

19.

Parker, M.A.: “Effect of Gelled Fracturing Fluids on the Conductivity of Propped Fractures,” Paper CIM/SPE90-92, 1990 CIM/SPE Technical Conference, Calgary, Alberta.

20.

Norman, L.R., Hollenbeak, K.H., and Harris, P.C.: “Fracture Conductivity Impairment Removal,” Paper SPE 19732, 1989 SPE Annual Technical Conference, San Antonio, Texas.

21.

McGowen, J.M., and McDaniel, B.W.: “The Effects of Fluid Preconditioning and Test Cell Design on the Measurement of Dynamic Fluid Loss Data,” Paper SPE 18212, 1988 SPE Annual Technical Conference, Houston, Texas.

22.

Cooke, C.E., Jr.: “Effects of Fracturing Fluids on Fracturing Conductivity,” JPT, (October, 1975) 1273-1282.

23.

Almond, S.W., and Bland, W.E.: “The Effects of Break Mechanism on Gelling Agent Residue and Flow Impairment in 20/40 Mesh Sand,” Paper SPE 12485, Formation Damage Control Symposium, Bakersfield, California, February 13-14, 1984.

24.

Harris, P.C.: “Chemistry and Rheology of Borate-Crosslinked Fluids at Temperatures to 300°F,” JPT (March 1993) 264-269.

91


APPENDIX A

where V is filtrate volume per area (m3/m2), v is filtrate velocity (m/s), n ′ is flow behavior index (dimensionless), and K ′ is consistency index (lbf-secn ′/ft2).

FLUID LOSS MODELS The shear rate for a power law fluid inside a porous medium is given by the equation 4v . . . . . . . . . . . . . . . . . . . . . . . . . . . . (9.1) 15)k (8

10

For n = 1, i.e., a Newtonian fluid, the two previous equations reduce to the classic equation for viscous fluid leakoff that is used in most simulators: VCv t . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (9.5)

The wall shear stress for a fluid is given by where

p 2L

(8 1015)k . . . . . . . . . . . . . . . . . . . . . . . (9.2)

. where is shear rate inside the core (sec -1), is superficial filtrate velocity (m/sec), is rock factor (dimensionless), k is core permeability (md), is core porosity (fraction), is shear stress inside the core (psi), p is differential pressure (psi), and L is core length (m). The two previous equations, along with Darcy’s law, can be used to determine the leakoff volume or rate behavior versus time for a power law fluid. The filtrate volume and rate are given by the following equations:

NOMENCLATURE . = shear rate inside the core (sec-1) = superficial filtrate velocity (m/sec) = rock factor (dimensionless) = core porosity (fraction)

p = differential pressure (psi)

n′

8 1015k n′ + 1 . . . . . . . . . . . . . . . . . . . . . . . . (9.3) 60t

k = core permeability (md) K ′ = consistency index (lbf -secn′/ft2) L = core length (m)

and n′ v n′1

n′ 1 n′1 72 p n′ + 1 n′ + 1 3n′1 K ′

8 1015k 60t

92

k p . . . . . . . . . . . . . . . . . . . . . . . . . . (9.6) fl

= shear stress inside the core (psi)

n′ 1 n′1 72 p n′ + 1 n′ + 1 V 3n′1 K ′

Cv 0.04469

n′ n′ + 1

n ′ = flow behavior index (dimensionless) V = filtrate volume per area (m3/m2) v = filtrate velocity (m/s)

. . . . . . . . . . . . . . . . . . . . (9.4)

APPENDIX B QUALITY ASSURANCE OF FRACTURING FLUID SYSTEMS

Four check points exist for ensuring and maintaining the quality of fracturing fluids used in stimulation treatments: • Halliburton Duncan Technology Center

As companies within the oil industry are challenged to operate with increasing financial concerns and narrower profit margins, they have become very aware of the cumulative impact of each step in the oilfield-development process. A natural extension of the impact of operating costs is the constant effort to improve quality.

• The field laboratory

To support our commitment to quality, Halliburton has initiated a comprehensive, interactive quality program with our vendors to ensure that the products we provide our customers perform as designed. Product conformance criteria, measurement parameters, and testing procedures have been defined for fracturing-fluid additives as part of a performance-tracking system.

Halliburton Duncan Technology Center

By installing point-of-source controls, the burden of routine quality control testing is removed from the field engineers and placed where it is most effective− at the vendor’s manufacturing facility. However, total quality management does not end with vendor testing. Vendors are required to submit samples to the Halliburton Duncan Technology Center, where comprehensive testing is conducted on random samples. As in most mature industries, technological advances in the petroleum industry proceed in incremental steps and not in the giant leaps associated with emerging technologies. The importance of incremental advances, however, should not be overlooked. These small advances have accumulated and resulted in production gains from wells that in the past would not have been drilled because the technology to safely complete the well did not exist, or the well would have been abandoned because of poor economic performance. Incremental advances have occurred in every discipline within the petroleum industry, from the techniques and equipment used to locate and extract hydrocarbons to the methods used to increase production and maximize recoverable reserves. Of all areas that undergo incremental technological advances, quality control offers the greatest potential for a positive financial impact on the viability of a well.

• The jobsite • Vendor facilities

Quality programs that are implemented between the manufacturer and Halliburton Duncan Technology Center ensure that the chemical and the performance criteria of a product conform to established standards. This quality program helps ensure that the products delivered to a field camp perform as designed, with minimum variance between lots. Halliburton Technology is responsible for molding the unique features and requirements of each quality check point into a unified quality program. The Technology Center is the center of criteria development, conformance testing, and conformance tracking of fracturing additives. The three other check points (the field lab, jobsite, and vendors) perform specific tasks and are extensions of the Technology Center.

The Field Laboratory The field laboratory is responsible for random functional testing of field samples to help ensure that they are performing as required. Job-specific testing and system optimization are performed by the field laboratory and are based on local field conditions. Pre-job planning is performed by the field laboratory. In short, the field laboratory supplies support and local expertise to field operations.

93


The Jobsite After comprehensive testing at the field laboratory, testing at the jobsite is still performed to confirm fluid properties and characteristics. The fluid system’s properties should be determined and verified before any equipment arrives on location. If major discrepancies are discovered between field lab results and the results obtained at the jobsite, the problems are evaluated more closely. Assistance from the field lab should be sought with jobsite testing. Attempts to fine tune or radically modify treatment schedules based on onsite test results during the treatment can cause gross errors. The small treatment volumes and relatively high percentage of measurement error associated with the equipment used to add components can magnify even small adjustments.

Vendors Halliburton works very closely with vendors of all products to ensure that quality conditions are fulfilled at all times.

QUALITY ASSURANCE GUIDELINES Before arriving on location, qualified personnel should complete the following tasks. 1. Clean the fracturing tanks. 2. Add biocide to the first load of water as it is transferred to the fracturing tank. Obtain a sample of the water from each tank. 3. Analyze the dissolved and suspended components in the water samples taken from the fracturing tanks. 4. Perform a bacteria count on the water samples. 5. Establish the base gel viscosity and pH. 6. Establish crosslink time control and make any necessary adjustments. 7. Perform break tests to determine the breaker package required to yield the desired break profile. 8. Test all proppants according to API RP 56 or API RP 60. IMPORTANT: Using the proper sampling technique is critical to the outcome of the tests listed previously.

94

After arriving at the jobsite, qualified personnel should perform the following tasks. 1.

Inspect the fracturing tanks and their contents for gross abnormalities.

2.

Measure base-gel viscosity and pH and adjust as required.

3.

Confirm that crosslink time is adequate and that a suitable crosslink is formed.

4.

Confirm that fluid additives have been added.

5.

Confirm fluid break on wells with BHST below 200°F.

After the chemistry of the fluid system has been confirmed at the field lab and at the jobsite, a successful fracture stimulation then becomes operation-dependent. IMPORTANT: Historically, fluid stability has shown little dependency on the water source if the base gel’s viscosity, pH, crosslinker concentration, and gel stabilizer concentration are within accepted criteria limits. This indicates that specialty testing (such as with a Fann Model 50 viscometer) is not necessary on routine treatments if the quality of the water source is known.

Checklist for Ballouts and Fracturing Jobs

____ Ambient temperature and fluid temperature have been measured and recorded.

To promote job safety and quality, make sure that the following procedures and equipment preparations have been completed.

____ The fluid system has been successfully pilot-tested with the gel.

Fluids and Additives Tanks ____ Tanks are clean inside and outside.

____ Fluid quality control and break tests were completed before the job.

____ Internal coatings of the tanks are perfect. If not, the tanks should be returned.

____ Necessary supplies of the proper additives are available on location.

____ All valves are operable, leak-free, and are fitted with proper opening and closing devices.

____ The method of injecting each additive has been documented, and the operators in charge of the process have been identified.

____ Tops of the tanks are skid-proofed (or are not slippery), and all hatches open fully. ____ Tanks are positioned level or leaning forward. ____ All ladders are secured. ____ Depth to the shelf above the wheels and the depth to the bottom of the tank has been gauged. Also, check the condition of the gauge line. ____ The suction manifold and its valves, rubber hoses, and unions are in good condition. The manifold is properly fitted with valves. Measure the height of the suction line above the bottom of the tank.

____ Methods of measuring the additive rate and the discharged amounts of fluid have been documented, and the operators in charge of the process have been identified. ____ Pumps are operating properly. (Check the condition of fluid transfer and the condition of additive pumps.) ____ Diesel tanks are full, and hoses and valve clamps are installed and in good condition.

____ Biocide has been added with the first load of water.

____ Diesel discharging equipment and measuring devices have been identified, located, and checked for proper operation. The measuring devices should be accessible for quick repair.

Mix Fluid

____ Measuring gauges are monitored constantly to track the volume of diesel used.

____ The source of the mixing fluid has been confirmed and tested. ____ Fluid-transport trucks are perfectly clean and committed to only the current job.

____ Tanks have been checked after the job to ensure that any remaining fluid has been removed or handled according to the customer’s wishes.

____ The amount of fluid hauled matches the amount charged to the customer. ____ The fluid is clean, fresh, and free of foul odors and discoloration. ____ The pH, bacterial content, specific gravity, and other measurement points are within quality standards.

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FRACPAC COMPLETION SERVICES Water Analysis A high-quality fracturing fluid is an essential element of a successful fracturing job. Water analysis allows the detection of any components that may jeopardize the quality of the fracturing fluid.

Fracturing Tanks Fracturing tanks must be kept clean and be functioning properly. The tanks should be steam cleaned and flushed with clean, fresh water before arriving at the jobsite. Residual gels, breakers, acids, rust, and various types of organic matter can cause or carry contamination. Contamination interferes with hydration and crosslinking and can result in high-temperature fluid instability, premature failure, or both. Fracturing tanks should be in sound mechanical condition, leak-free, and fitted with valves and manifolds that operate properly. Properly operating tanks and peripheral equipment help ensure that control over mix concentrations, personnel safety, and environmental compliance are all maintained. All fracturing tank tops should be coated with non-slip material and all ladders should be attached securely to the tanks. When a fracturing tank is emptied, 10 to 20 bbl of fracturing fluid may remain in the bottom of the tank. To reduce this volume, elevate the rear of the fracturing tank to allow the fluid at the bottom of the tank to flow toward the manifold. Locate the fracturing tank higher in elevation from the blender, and restrict the length of the inlet hoses to less than 50 feet. Short hose lengths will reduce the likelihood of the blender losing prime, which could force a shutdown of equipment and jeopardize the success of the treatment.

Water Quality Source water should be tested for quality and rated acceptable before it is used to mix a fracturing fluid. Analysis of the source water should be performed to detect components within the water that may alter fracturing fluid qualities. The degree of alteration depends on several qualities that follow: • Fluid system • Concentration of the contaminant • Expected treatment temperature

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• Contact time between the contaminant and the fluid system • pH of the fluid system Because of the many factors that can affect fluid quality, it is not always possible to set a specific limit on each individual factor within the fluid system. Source water should be pilot-tested before using it in a fluid system. IMPORTANT: The subsequent maximum concentrations and temperature limitations are guidelines. They are not intended to replace sound chemical or engineering principles.

Iron (< 20 ppm) Dissolved iron exists in two valence states in water: ferric iron (Fe+3) and ferrous iron (Fe+2). Ferric iron will start to precipitate as ferric hydroxide at pH 2.0 and is completely precipitated at pH 3.5. For waters with a pH higher than 3.5, any ferric iron present is in the form of ferric oxide (rust). As a solid material, ferric iron has minimal effect on fracturing fluid properties. Ferrous iron is soluble in waters with a pH of up to 7.5. This form of iron can alter the valence states of metallic crosslinkers in fracturing fluids, or act as a catalyst for oxidizing polysaccharide gelling agents. Excessive amounts of ferrous iron can cause a fracturing fluid to over-crosslink or to lose stability and shear stability, or both. Excessive amounts of iron are usually introduced to fracturing fluids by contact with rusty fracturing tanks or transport tanks. Ferrous iron does not begin to precipitate until the fluid reaches pH > 7.5. Some fracturing fluids are incompatible with source waters that contain as little as 8 ppm of iron.

Phosphates (< 5 ppm) Phosphates are strong sequestering agents for metals, and they will interfere with crosslinking. A sufficient concentration of phosphate can prevent crosslinking completely. If phosphates exist in the source water, the dosage of crosslinker may have to be increased to overcome the effects of the phosphates.

Bicarbonates (< 1,000 ppm) Zirconate crosslinkers require bicarbonate ion for proper control of reaction kinetics; however, excessive bicarbonate levels can be detrimental. Bicarbonates in concentrations greater than 1,000 ppm can delay the crosslink for some

Table 9.1B — Source Water Guidelines Iron

20 ppm

Phosphates

5 ppm

Bicarbonates

1,000 ppm

Reducing agents

0 ppm

Calcium and magnesium

2,000 ppm

Specific gravity

1.038

pH

6.0 to 8.0

Temperature

40°F to 100°F

Bacteria

105/mL

fluids. This can usually be overcome in some fluid systems by adjusting the pH with hydrochloric acid (HCl). Whenever possible, source water should be evaluated and recommended based upon a preferred bicarbonate level less than 500 ppm to avoid pH adjustments with acid.

prevent a gelling agent from fully uncoiling and hydrating. A partially hydrated gel can be unstable. For best results, use a source water that closely matches the characteristics of fresh water.

Solids Reducing Agents (0 ppm) Contaminants such as bisulfite can prevent proper gel hydration, cause premature crosslinking, or neutralize oxidizing breakers. They can also alter the valence state of metal ions. To overcome such problems, add a small volume of oxidizer such as ammonium or sodium persulfate.

Solids are often a source of bacteria. They can cause emulsions to form and stabilize, and may cause damage to the proppant pack and permeability. Solids can be removed by filtration.

pH Hardness (Calcium and Magnesium < 2,000 ppm) Waters that contain excessive concentrations of calcium and magnesium may exhibit problems with gelling, crosslinking, and maintaining temperature and shear stabilities. Adjust the pH with sodium hydroxide (NaOH).

Most polymer gelling agents will adequately disperse and hydrate if the mix water has a pH of 6.0 to 8.0. A mix water with a pH greater that 8.0 may result in a slow or poorly hydrated gel. A mix water with pH of less that 6.0 can hydrate rapidly and yield gel balls, lumps, or “fisheyes” in the gel.

Temperature (40°F to 100°F) Sulfates Some crosslinkers may be precipitated by sulfate ion in solution. Sometimes increasing the crosslinker dosage will overcome this problem.

Specific Gravity Specific gravity is an indicator of the degree of dissolved salts in a fluid. Excessive levels of dissolved salts can

As the temperature of the mix water increases, the gelling agent’s rate of hydration accelerates. At temperatures approaching or exceeding 100°F, the rate of hydration may cause gel balls, lumps, or fisheyes to form. Adding the gel as a liquid gel concentrate (LGC) can ease dispersion problems and reduce the possibility of fisheyes forming. The pH of the source water can also be adjusted to retard the hydration rate of the gelling agent. At mix-water temperatures below 40°F, long hydration times may be experienced and it may be necessary to heat the mix water.

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Table 9.2B — Effect of Bacteria on Base Fracturing Gel

Bacteria Count

Days before catastrophic viscosity degradation of the base gel will occur

104

3 days

105

2 days

106

less than 1 day

Adding Biocide to Mix Water Bacteria are capable of ingesting polysaccharide gelling agents as a food source, and by doing so can double their population in 20 minutes. Many bacteria found in mix water can cause formation damage and hydrogen sulfide gas production. Typical symptoms of bacterial contamination are the following: • Black gel • Foul, putrid odor of fluid • A change in gel pH in combination with a lowering viscosity

To prevent problems associated with bacteria growth, add biocide to the fracturing tank with the first load of water. Follow the manufacturer’s recommendation for dosage. Bacterial growth is the greatest at temperatures between 80°F and 100°F, and a pH from 4.0 to 8.0. It is important to treat the source water before the bacteria population has the opportunity to produce a significant level of enzyme, which can remain active even after the bacteria has been killed. On jobs where the gel has been mixed and a delay occurs, the gelled fluid can be preserved by increasing its pH to at least 11.0. Raising the pH will kill any remaining bacteria and help denature any enzymes in the fluid. The effects of bacteria on base-gel degradation are shown in Table 9.2B.

• Delayed or incomplete crosslink IMPORTANT: Make sure that the pH is lowered to the proper level for fluid performance before starting the job.

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Chapter 10 INTRODUCTION Proppant selection is very important to the success of completion and stimulation operations, especially in semiconsolidated formations. Achieving good sand control and obtaining maximum well productivity are primary treatment goals that must be considered when selecting proppants for a FracPac job.

SAND CONTROL To achieve good sand control, the many variables that characterize sand production and migration must be studied. These include formation damage depth, production rates, drawdown pressures, critical flow rate, formation mechanical properties, proppant size, and formation sand size distribution. Once these are understood, a method can be selected for controlling sand. The methods involve the use of mechanical devices, gravel packing, hydraulic fracturing, and resin-related products. Mechanical devices, such as wirewrapped screens, prepacked screens, and slotted liners, can stop the movement of formation sand into the wellbore. Gravel packing–the placement of a high-permeability proppant bed between the wellbore and the formation– further prevents fines migration to the wellbore. In addition to proppants for conventional gravel-packing jobs, lowdensity and steam-resistant gravels are available for special applications. Table 10.1 lists some of the criteria that the API recommends should be met by gravel-pack proppants.1 Hydraulic fracturing can create highconductivity fractures that extend beyond

wellbore damage. This can significantly reduce reservoir drawdown pressures, decreasing the possibility of mechanical formation damage during production. In some cases, highly conductive fractures can significantly increase the effective wellbore radius, making it possible to produce at higher rates without exceeding critical fluid velocities in the formation. Thus, this can also be an effective means of sand control.

Proppant Selection

Consolidated resin systems, such as SANDFIX, HYDROFIX, and Eposand, can be pumped into a formation to provide formation consolidation and stability. In fracturing applications in which a screen will not be set later for sand control, resin-coated proppants can be used. Table 10.2 lists some common resin-coated sands.

PRODUCTIVITY Proppants are used in hydraulic fracturing to provide a path for reservoir fluids to flow into the wellbore. A formation can be fractured to stimulate production or to bypass damage around the wellbore. In either case, proppants must maintain conductivity under stress after pumping pressure is removed and closure stresses are applied at the fracture faces. Therefore, strength is an important property of proppants used in hydraulic fracturing. Some of the proppant types used in fracturing applications are displayed in Table 10.3, with general strength categories being indicated for the uncoated manmade proppants. Proppant size is also an important factor in fracturing operations. Under most conditions, large proppants have greater

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Table 10.1 — Recommended Criteria for Properties of Gravel-Pack Proppants Recommended Criteria

Property

At most 0.1% by weight can be larger than the first sieve size. Proppant size*

At least 96% by weight should pass the second sieve and be retained on the sixth sieve. At most 2% by weight can be smaller than the last designated sieve size.

Sphericity

0.6

Roundness

0.6

Acid-soluble materials Turbidity Clay and soft particle content

1% by weight 250 Formazin Turbidity Units 1% by volume 8% by weight for 8/16-mesh sand

Crush-Resistance Test (% fines by weight)

4% by weight for 12/20-mesh sand 2% by weight for 16/30- and 20/40-mesh sand 2% by weight for 30/50- and 40/60-mesh sand

* For testing an M/N-mesh sand, six sieve sizes are used. The first sieve is slightly coarser than an M-mesh sieve, and the second sieve is an M-mesh sieve. The third, fourth, and fifth sieves increase in fineness between (but not including) M-mesh and N-mesh. The sixth sieve is an N-mesh sieve.

conductivity than small proppants. Table 10.4 indicates the proppant sizes that are available for natural sands and manmade proppants. API guidelines for testing proppants used in fracturing are found in two API publications: API RP 56: Testing Sand Used in Hydraulic Fracturing Operations and API RP 60: Testing High Strength Proppants Used in Hydraulic Fracturing Operations.2,3

PROPPANT SIZE Depending upon the application, proppants can be selected for complete sand control, maximum productivity, or a balance between sand control and productivity.

Complete Sand Control The goal in complete sand control is to prevent all formation sand from penetrating the gravel pack. All formation sand, regardless of size ranges, must be stopped at the interface between the formation and the pack. This may require a very small proppant, which can result in lower than normal fracture conductivity and well productivity. However, it usually eliminates the production decline that would otherwise result from invasion of formation fines.

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Maximum Productivity Since sanding tendency is usually not a major concern when a treatment is designed primarily for maximum productivity, the proppant size is selected that offers the highest conductivity at the expected closure stress.

Balanced Sand Control and Productivity To optimize sand control and productivity, the distribution of pore throat size in the proppant bed and the distribution of formation sand size must both be considered. The proppant can be sized to allow the smaller formation particles to pass through the proppant bed if they cause only minimal damage to the bed’s conductivity and permeability. Current practices indicate that the stresses imposed on the fracture face during fracturing may help prevent sand migration into the proppant bed. This is one possible explanation for the success of larger proppants, such as 20/40-mesh, which have displayed increased conductivity, reduced drawdown, and, in most cases, good sand control.

Table 10.2 — Common Resin-Coated Sands Precoated

Coated On-The-Fly

Precured

Partially Cured

Curable

AcFrac PRB

AcFrac Ultra SB

AcFrac CR

PropLok 11

TEMPERED LC

AcFrac CR 5000

PropLok 12

TEMPERED DC

SUPER LC

PropLok 32

TEMPERED H

SUPER DC

PropLok 33

AcFrac PR-5000

SUPER HS

* Manmade proppants can be resin-coated on special order.

Table 10.3 — Proppants Used for Fracturing Applications Class

Examples

Type

Ottawa sand Brady sand

Natural Sands

Resin-coated sand Low-quality sand Intermediate-Strength Ceramics

EconoProp CarboLite LWP Plus

Intermediate-Strength Bauxite

Carbo-Prop HC INTERPROP PLUS

Manmade Proppants

High-Strength Bauxite

SUPERPROP ULTRAPROP PLUS High-strength bauxite

Resin-Coated Proppants

Any proppant

Table 10.4 — Proppant Sizes Available for Fracturing Applications Mesh

Natural Sands

Manmade Proppants

12/20

✓

✓ ✓

16/20 16/30

✓

20/40

✓

✓

40/70

✓

✓

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FRACPAC COMPLETION SERVICES Table 10.5 — Proppant Selection Guide Service

Proppant Sizing Criterion

Proppant Size

Screen Size

Gravel Pack

Formation sand size distribution

5 times mean diameter of formation sand

Maximum

FracPac

Balanced sand control and conductivity

Between Gravel Pack and OptiPac

Maximum

OptiPac

Balanced sand control and conductivity

Select for maximum conductivity

na

OptiFrac

Formation conductivity


na

Fracturing

Formation conductivity


na

PROPPANT SELECTION RECOMMENDATIONS

• Quantification of critical flow rates and verification with sand production models

There is some disagreement in the industry regarding the selection of proppant size. Saucier and Penberthy independently found that the effective bridging of formation sand and the prevention of its movement into the proppant pack can be achieved at a gravel to median formation sand size ratio of 5 to 6 or less.4,5

• Determination of formation mechanical properties

Leone claimed that Saucier and Penberthy did not use proper formation sand materials in their studies.6 In those studies, very little cementing material was available to bond individual sand grains to one another in the washed out sands that were used. By using the actual formation core plugs and carcass material to simulate formation materials, Leone found that effective sand control could be obtained at a 16 to 1 ratio of mean gravel diameter to mean formation sand diameter. He suggested that this high ratio was due to the agglomerate forms of produced formation sand consisting of two or more grains as opposed to the individual grains that were produced in the Saucier and Penberthy studies.

• Determination of proppant embedment tendencies in soft formations

Oyeneyin et al. suggested that all the then-current sizing formulas might be too general because they fail to consider the formation sand environment and the operational conditions.7 Oyeneyin et al. proposed a set of semiempirical equations to predict the bridging effectiveness of the selected gravel under specified operational conditions. Table 10.5 outlines a general proppant selection guide. Halliburton recommends that, as part of the selection process, important aspects of treatment design be studied through experimental and numerical analyses. These analyses include

102

• Determination of formation sand size distribution • Characterization of the flow field around the gravel pack and, if necessary, around a short fracture

REFERENCES 1 Recommended Practices for Testing Sand Used in Gravel-Packing Operations (API RP 58), American Petroleum Institute, Washington, D.C. (1986). 2 Recommended Practices for Testing Sand Used in Hydraulic Fracturing Operations (API RP 56), American Petroleum Institute, Washington, D.C. (1983). 3 Recommended Practices for Testing High Strength Proppants Used in Hydraulic Fracturing Operations (API RP 60), American Petroleum Institute, Washington, D.C. (1989). 4 Saucier, R.J.: “Considerations in Gravel-Pack Design,” JPT (January 1974) 19-24. 5 Penberthy, W.L. Jr., and Cope, B.J.: “Design and Productivity of Gravel-Packed Completions,” JPT (October 1980) 1679-1686. 6 Leone, J.A., Mana, M.L., and Parmley, J.P.: “Gravel-Sizing Criteria for Sand Control and Productivity Optimization,” Paper SPE 20029, SPE California Regional Meeting, Ventura, California, April 4-6, 1990. 7 Oyeneyin, M.B., et al.: “Optimum Gravel-Sizing for Effective Sand Control,” Paper SPE 24801, 1992 SPE Annual Technical Conference and Exhibition, Washington, D.C., October 4-7.

Chapter 11

INTRODUCTION Proper selection and execution of a perforating program is essential to the success of a FracPac completion. Perforations are the fluid flow channels whereby treatment fluids enter a formation and produced fluids leave to flow up the completion tubulars. Thus, perforation characteristics can greatly affect induced fractures and reservoir production. This chapter discusses how perforation characteristics influence fluid flow, what factors must be considered in selecting a perforating system, and how computer programs are used to estimate downhole perforator performance and resulting wellbore flow parameters.

OPTIMIZING FLUID FLOW The ultimate goal in perforating is to establish effective fluid communication between the wellbore and the reservoir.1 The perforating program should be designed to remove or minimize any impedances to the desired fluid movement. Major factors that influence fluid flow through perforations are perforating geometry, damaged zones around the wellbore, and crushed zones around the perforations.

Terminology Perforating geometry is one aspect of perforating over which considerable control can be exercised. As illustrated in Figure 11.1, perforating geometry includes gun phasing, shot density, perforation diameter, and perforation length. Varying the geometry can produce significant variations in fluid flow. The geometry that should be selected for a particular job will be determined by well conditions and the type of perforating application.

One well condition that influences the selection of perforating geometry is formation damage caused by drilling fluids. This occurs long before the well is perforated and can result in decreased permeability. When drilling fluids enter the formation, they can deposit solid matter, cause clay swelling, and induce chemical precipitation, all of which reduce the effective size of the pores available for fluid flow. The affected region about the wellbore is called the damaged zone. A main objective in perforating is to penetrate beyond this zone.

Perforating

The perforating process itself can also cause damage to the formation. The radial displacement of formation materials during the creation of the perforation crushes and compacts the region immediately surrounding the perforation. The affected envelope around the perforation is called the crushed zone (Figure 11.2) and usually exhibits reduced permeability, typically on the order of 40 to 60% of the permeability of the undamaged formation. As measured from the wall of the perforation tunnel, the depth that crushed-zone damage extends into the formation usually does not exceed one perforation diameter. Another one of the important goals in perforating is to use equipment and techniques that minimize perforating damage. Reductions in fluid flow between the borehole and formation are often described in terms of skin effect, as though skins or membranes are present that restrict fluid movement. The terms crushed-zone skin effect and damagedzone skin effect are commonly used with this connotation.

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Effects of Varying Perforating Geometry Mathematical models have been derived to study the effects of perforating geometry on flow rates and to predict downhole perforator performance. The next four figures present the results of applying a mathematical model to completion conditions that were identical, except that one aspect of perforating geometry varied in each case. For each factor in perforating geometry that varied, the different relationships that arose between bottomhole pressure and liquid flow rate were determined. Neither a crushed zone nor a damaged zone was assumed to exist.

Gun Phasing Perforation Diameter

Pentration

Shot Density

Gun Phasing

Figure 11.1 — Perforating geometry involves gun phasing, shot density, perforation diameter, and perforation length.

Casing Cement

Undisturbed Formation (Permeability ku)

Damaged Zone (Permeability kd)

Crushed Zone (Permeability kc)

Figure 11.2 — Drilling produces a damage zone around the wellbore, and perforating creates a crushed zone around the perforation. Permeability is less in both zones than in undisturbed formation.

Gun phasing refers to the angular measurement between adjacent perforations produced by a perforating gun, when the perforations are projected to lie in a single plane normal to the wellbore. Gun phasing can have a significant effect on flow rates. In Figure 11.3, four phasings are considered: 0˚ (which is equivalent to 360˚ and in which all of the charges have the same vertical orientation), 180˚, 120˚, and 90˚. The figure indicates that the highest flow rate is obtained with the smallest (nonzero) phase angle. This is reasonable since the more uniformly shots are distributed around the circumference of a wellbore, the less interference there is between fluids flowing radially toward the wellbore.

Shot Density Shot density is the number of perforations placed over an interval of unit length in the wellbore. It is usually expressed in shots per foot (spf) or shots per meter (spm). The results of Figure 11.4 show that the highest flow rate is obtained with the highest shot density. Since 0˚ phasing is used and since Figure 11.3 showed this to be the least effective phasing, other phasings would be expected to yield higher flow rates. High shot densities should be used in laminated formations and in formations where there is significant contrast between horizontal and vertical permeability.

Perforation Length In Figure 11.5, the highest flow rate is obtained with the longest perforation length. Since 0˚ phasing is used and since Figure 11.3 showed this to be the least effective phasing, other phasings would be expected to yield higher flow rates. It should be noted that under actual well conditions where a damaged zone does indeed exist, the highest flow rates will be obtained when the perforation

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Perforating Geometry Effects

Perforating Geometry Effects

Shot Density

Gun Phasing 5,000 90°

2,080 120° & 180°

2,060

0°

2,040 2,020 2,000

Flowing Bottomhole Pressure (psig)


2,100

Perforation Diameter Perforation Length Shot Density Gun Phasing Damaged Zone Crushed Zone

0.5 in. 7.0 in. 4 spf Variable None None

4,000

0.5 in. 7.0 in. Variable 0° None None

3,000 6 spf

2,000

4 spf 2 spf

1,000 1 spf

0

1,980 1,550


1,560

1,570 1,580 1,590 Liquid Rate (BLPD)

0

1,600

Figure 11.3 — The highest flow rates are obtained with the smallest nonzero phase angle.

1,000 2,000 3,000 Liquid Rate (BLPD)

4,000

Figure 11.4 — The highest flow rates are obtained with the largest shot density.

Perforating Geometry Effects Perforation Length 3,500 Flowing Bottomhole Pressure (psig)

tunnel extends beyond the damaged zone. The distance that the perforation tunnel extends beyond the damaged zone affects flow rates much more in low-permeability zones than in high-permeability zones. It should also be noted that the actual flow rate is a function not only of perforating geometry, but also of damaged-zone radius, damaged-zone permeability, formation permeability, and borehole size.


3,000

0.5 in. Variable 4 spf 0° None None

2,500 2,000

16 in. 8 in. 4 in. 2 in.

1,500 1,000

Perforation Diameter

Minimizing Crushed-Zone Skin Effect It is important to minimize the crushed-zone damage. The next three examples examine the influence of perforation diameter, perforation length, and gun phasing on reducing crushed-zone skin effect. Each example assumes a shot density of 4 spf, no damaged zone, and an annular-shaped crushed zone 0.5 inches thick around each perforation. The crushed zone permeability is designated kc ; the permeability of the undisturbed formation is designated ku.

1,200

1,400 1,600 1,800 Liquid Rate (BLPD)

2,000

Figure 11.5 — The highest flow rates are obtained with the longest perforation length.

Perforating Geometry Effects Perforation Diameter 4,000 Flowing Bottomhole Pressure (psig)

Figure 11.6 demonstrates that the highest flow rate is obtained with the largest perforation diameter. Since 0˚ phasing is used and since Figure 11.3 showed this to be the least effective phasing, other phasings would be expected to yield higher flow rates. Perforation entry hole diameter is of prime importance in poorly consolidated formations and in gravel-packing operations: large diameters are important in ensuring that the pressure drop across the perforation is kept to a minimum, thereby preventing sand inflow into the well.

1,000

3,000

0.4 in.

2,000


Variable 7.0 in. 4 spf 0° None None

0.3 in. 0.2 in.

1,000

0.1 in.

0 0

500 1,000 1,500 Liquid Rate (BLPD)

2,000

Figure 11.6 — The highest flow rates are obtained with the largest perforation diameter.

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Minimizing Crushed-Zone Skin Effect Varying Perforation Diameter Perforation Diameter Perforation Length Shot Density Gun Phasing Damaged Zone Crushed-Zone Thickness

1.1

Open Hole

1.0 Productivity Ratio

Variable 12 in. 4 spf 0° None 0.5 in.

kc /ku = 1.0 0.4 0.9 0.2 0.8 0.1 0.7

0

0.25 Perforation Diameter (in.)

0.50

Figure 11.7 — Large-diameter perforations are more effective than small-diameter perforations in overcoming crushed-zone skin effect. (After Locke2)

Minimizing Crushed-Zone Skin Effect Varying Perforation Length

Well Flow Efficiency

1.0

0.9

9 in.

0.7

Perforation Diameter Perforation Length Shot Density Gun Phasing Damaged Zone Crushed-Zone Thickness

1.0

0

Figure 11.8 — Long perforations are more effective than short perforations in overcoming crushed-zone skin effect. (After Locke2).

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Figure 11.9 compares the permeability ratio and productivity ratio for 0˚ and 90˚ gun phasings. PR values are clearly higher for the 90˚ phasing. Notice that PR begins to decrease dramatically when the permeability ratio falls below about 0.3.

Figure 11.10 compares PR values when a particular zone has no damage, when it has invasion damage only, and when it has both damage due to invasion and crushing due to perforating. Damaged-zone thickness is assumed to be 8 inches; damaged-zone permeability is denoted kd . At any particular point, vertical and horizontal permeabilities are assumed to be equal.

0.5 in. Variable 4 spf 0° None 0.5 in.

0.5 Crushed-Zone Permeability (kc /ku) Formation Permeability

Figure 11.8 plots kc/ku versus well flow efficiency for two penetration values. Well flow efficiency (WFE ) is the ratio of the flow from an actual perforated completion to that from an ideal perforated completion of identical geometry. The figure indicates that the deeper penetration gives the higher WFE values. Notice that when kc/ku drops below about 0.3 for either penetration (i.e., crushed-zone permeability is about one-third of undamaged formation permeability or less), WFE begins to decrease rapidly. This is significant since kc/ku can be less than 0.3 when perforations are not backflushed or cleaned up. So, no matter how deep the penetration, clean perforations are necessary for effective fluid communication between the formation and the wellbore.

The Damaged Zone

18 in.

0.8

Figure 11.7 compares perforation diameter and productivity ratio for different values of kc/ku. Productivity ratio (PR ) is the ratio of the production flow of a perforated interval to the equivalent openhole flow potential of the same interval. The openhole completion is assumed to have the same properties as the completed well except that its total skin effect is zero. For an ideal completion, the PR would be unity (1.0). In Figure 11.7, for a given value of kc/ku, larger perforation diameters yield larger PR values. Thus, all other factors being equal, larger-diameter perforation will be more effective in overcoming crushedzone damage and will permit a larger volume of fluid to flow than will smaller-diameter perforations.

Curve A plots penetration versus PR when there is no damage of either type. Curve B shows that when perforation damage is introduced (kc/ku = 0.2), PR drops by a significant amount. If both perforation damage (kc/ku = 0.2) and invasion damage (kd /ku = 0.4) are present, PR drops even more as shown by Curve D. In each of these cases, shot density is 4 spf.

Comparison of curves A, B, and D shows that attaining a PR of 0.8, when no damage is assumed, requires perforations with penetration less than 2 inches. Perforation damage alone increases this to nearly 6 inches, while the addition of invasion damage increases the required penetration to more than 10 inches.

Minimizing Crushed-Zone Skin Effect Varying Gun Phasing 1.3

90°

1.2

Productivity Ratio

Curves C, D, and E compare PR for shot densities of 2, 4, and 8 spf when both the damaged and the crushed zones are present. As expected, PR increases as shot density increases. It should be noted that when perforations extend past the damaged zone, there is an increase in the rate at which PR increases with increased penetration. Thus, to overcome the effects of the damaged zone, high shot densities and deep-penetrating charges should be used. Formations that have different vertical and horizontal permeabilities, that have low-permeability streaks, or that contain laminated shale also require high shot densities for effective fluid communication between the reservoir and the completion tubulars.

1.1 0° 1.0

Open Hole

0.9

0.8

Perforation Diameter Perforation Length Shot Density Gun Phasing Damaged Zone Crushed-Zone Thickness

Differential Pressure

Flow through a perforation can be hindered not only by the surrounding crushed zone but also by any debris that might be in the perforation. Contaminants from wellbore fluids and remnants from the charge liner and case can remain in the perforation tunnel. Thus, clean fluids that do not react with formation clays should be in the well when perforating, and the perforating charges and gun systems should be as debris-free as possible.

1.0

0

Productivity Ratios for Various Damage Effects 1.2

Convergent Flow Plus Crushed Zone, kc /ku = 0.2

1.0

Convergent Flow Only

Shot Density 4 8

A

0.8

4

4

2

0.6 B

0.4

C Damaged-Zone Thickness = 8 in. kd /ku = 0.4 kc /ku = 0.2

D

0.2

Perforating underbalanced promotes cleaner, betterflowing perforations. Formation pressure being greater than wellbore pressure causes formation fluids to surge back toward the wellbore. This surge immediately cleans out charge debris from the perforation tunnel and removes compacted rock from the crushed zone. Wellbore fluids

0.5 Crushed-Zone Permeability (kc /ku) Formation Permeability

Figure 11.9 — Radially dispersed perforations are more effective than inline perforations in overcoming crushed-zone skin effect. (After Locke2)

Productivity Ratio

The previous section illustrated how perforating geometry can be used to overcome damaged and crushed-zone skin effects. Differential pressure can also be used to reduce crushed-zone skin and other impedances to fluid flow through perforations. Differential pressure is wellbore pressure minus formation pressure. A balanced condition exists when differential pressure is zero, i.e., wellbore pressure equals formation pressure. An underbalanced condition exists when differential pressure is negative, i.e., wellbore pressure is less than formation pressure. Conditions are overbalanced when differential pressure is positive, i.e., wellbore pressure exceeds formation pressure.

0.5 in. 18 in. 4 spf Variable None 0.5 in.

E Gun Phasing 90°

0 0

2

4 6 8 10 Perforation Length (in.)

12

Figure 11.10 — Damaged-zone skin effect can be overcome by using high shot densities and deep-penetrating charges. (After Bell3)

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Berea Sandstone Target

Core Flow Efficiency (CFE)

0.8 0.7 0.6

CFE 0.7 to 0.8 at Standard Test Pressure (200 psi)

Threshold Pressure for Optimum Cleanup (≈ 150 psi)

0.5

Underbalanced Pressure for Optimum Cleanup 0.4

API Berea Sandstone Target

0.3 0.2 0.1 10 25

50 100 Underbalanced Pressure (psi)

200

Figure 11.11 — Underbalanced perforating promotes perforation cleanup. However, increases in cleanup become smaller with increases in underbalance. (After Bell3)

do not rush into the perforation; thus, plugging due to debris and formation damage due to incompatible fluids are minimized. Figure 11.11 compares underbalanced differentials with core flow efficiency for a Berea sandstone target. Core flow efficiency (CFE) is essentially the ratio kp/ku, where kp is the permeability of the perforated core and ku is the permeability of the unperforated core. CFE is 1.0 for a clean, undamaged core and is 0.0 for a perforated core that permits no flow. In Figure 11.11, CFE is about 0.1 after perforating and before cleanup. CFE increases with increasing underbalance and levels off to about 0.7 at approximately 200 psi underbalance. The tests used to generate this data were performed with kerosene saturating the pore spaces of the Berea cores. The tests thus indicate the required underbalance needed when a slightly compressible fluid occupies formation pore spaces. The differential pressure at the time of perforating is adjusted according to the application, the reservoir fluid (liquid or gas), and the perforating system that is used. In most applications, underbalanced perforating is desired because of the associated cleanup advantages. However, extreme-overbalance perforating, such as Halliburton’s PerfStim service in which very high positive differentials are applied, is becoming popular in some fracturing operations. In PerfStim operations, the differential is generally 20 to 40% above the pressure required to fracture the formation.

108

Either wireline or tubing can be used to run perforating guns downhole and position them across the zones to be perforated. In wireline-conveyed operations performed in casing, production equipment has usually not yet been installed, and temporary pressure-control equipment is attached to the wellhead. For safety reasons, a slight overbalance of 100 to 200 psi is typically employed in this case. In tubing-conveyed operations and in through-tubing wireline-conveyed operations, production equipment is installed before perforating, and underbalances of 1,000 to 3,000 psi can be used. To avoid casing failure and packer unseating, the design for underbalance jobs must take into account casing collapse pressures and differential pressures across packers and other tools in the completion string. Tubing-conveyed systems are also used in extremeoverbalance perforating because the production pressure equipment must be in place to contain the high wellhead pressures that are involved. In these operations, nitrogen is typically used to generate a wellbore pressure that is 1.2 to 1.5 times formation pore pressure. When the perforating charges are detonated or when a shear plug later expends, the compressed nitrogen produces an extreme pressure surge through the perforations and formation. This surge fractures the formation. After the initial surge, the treatment is typically continued by pumping an additional two tubing volumes of nitrogen with commingled sand and/or acid. In unconsolidated formations, perforating with extreme overbalance eliminates concerns about sand flowing into the wellbore around the guns. In addition, subsequent pumping with commingled sand and optional resin serves to prepack the perforations.

PLANNING AN EFFECTIVE PERFORATING JOB The key to effective perforating is planning long before it is time to perforate. This will ensure that the best equipment and techniques are selected. The characteristics of the formation, the perforating method that will be used, the hardware that will be in the well, and the well conditions expected at the time of perforating must all be considered.

Formation Characteristics Formation characteristics to be considered include depth, lithology (sand, lime, dolomite), pore fluid (gas, oil, water), and pressure. Additionally, other pertinent information should be gathered such as porosity, permeability, formation compressive strength, fluid densities, watercut, irreducible water saturation, and skin damage. Also, is the zone fractured? Does it contain shale stringers? Is this a

recompletion of the formation? Has this same zone been completed in a nearby well, and if so, what were the formation characteristics, completion objectives, well conditions, perforating equipment, perforating techniques, and perforating results? All this information can begin to indicate what type of gun, charge, and perforating method should be used. However, completion objectives and well conditions must be examined closely before a final decision can be made.

Small Cross Section; Large Pressure Drop Low Flow Rate

Completion Types

Screen

Three completion types will be considered: natural completions, completions requiring sand control, and completions requiring stimulation. Natural completions are discussed to emphasize the special requirements of FracPac completions, which combine sand control and stimulation. The underlying goal in all perforating jobs is to establish effective fluid communication between the formation and the wellbore; however, the method used to achieve this is heavily influenced by formation characteristics. Since the order of importance of the perforating geometrical factors (gun phasing, shot density, perforation length, and perforation diameter) can be different for different completion types, the completion type has a significant bearing on which perforating system is selected.

Formation Cement Casing

Liner

Large Cross Section; Small Pressure Drop High Flow Rate

Figure 11.12 — Pressure drops across large-diameter perforations are smaller than across small-diameter perforations. With small pressure drops, there is less potential for sanding.

Natural Completion Natural completions are those in which no stimulation or sand control operations are required. The objective is to maximize PR . The order of importance of the perforating geometrical factors is usually considered to be 1. Shot density 2. Perforation length 3. Gun phasing 4. Perforation diameter In natural completions, particular attention should be paid to perforation length to ensure that perforations extend beyond the damaged zone, where possible. As Figure 11.10 demonstrated, PR increases more rapidly as a function of perforation length once the perforation tunnel extends past the damaged zone into the higher-permeability undisturbed formation.

Sand Control The objective in sand control operations is to prevent the formation from deteriorating around the perforation tunnels. When such deterioration occurs, the resulting materials block the perforation tunnels and can clog the casing and tubing. In unconsolidated formations, sanding can occur if there is an appreciable pressure drop between the formation and the wellbore, and the forces cementing the sand grains together are thereby exceeded. Since this pressure drop is inversely proportional to the perforating cross section, the probability of sanding can be minimized by maximizing the total perforated area available for fluid flow. This is controlled primarily by perforation diameter and shot density. The larger the perforation diameter and the higher the shot density, the larger will be the perforated area and, for a given production rate, the smaller will be the velocity of the produced fluid. See Figure 11.12.

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In formations requiring stimulation, the diameter and distribution of the perforations are most important. Perforation diameters and shot densities are selected to control pressure drops across the perforations and thereby minimize the demands placed on pumping equipment.

Formation Ball Sealer Perforation

Induced Fracture

Hydraulically

Casing

Cement

Figure 11.13 — In stimulation operations, ball sealers stop flow through the perforations that are first to accept the stimulation fluid.

Gun phasing and orientation are also important factors. When the direction of the principal stresses in the formation are known, perforation stability in poorly consolidated reservoirs can be improved by using 180˚ phasing oriented perpendicular to the least principal stress or in the direction of the maximum stress. Thus, the order of importance of the geometrical factors for sand control is 1. Perforation diameter 2. Shot density 3. Gun phasing and orientation 4. Perforation length

If the formation to be stimulated is thick or contains multiple zones with different reservoir conditions, limited entry stimulation techniques may be used. These techniques can require relatively large distances between the perforations, and the distances between adjacent perforations can vary from one perforation pair to the next. When limited entry techniques are not used, good vertical distribution of the perforations is necessary to optimize the vertical extent of the treatment. A shot density of 4 spf is usually sufficient. The radial distribution of perforations can also have a significant bearing on the effectiveness of the treatment. In fracturing operations, for example, if 90˚ phasing is used instead of 0˚ phasing, then perforations are more likely to align with the orientation of the natural fractures and in accordance with stress variations in the formations. The perforations thus provide a less tortuous path for the fracturing fluid to enter the formation. If the stress direction is known, then 180˚ phasing aligned with the preferred fracture direction can significantly reduce initiation and treating pressures by providing a direct path to the fracture and eliminating near-wellbore tortuosity. To ensure that fracturing occurs through as many perforations as possible, ball sealers (Figure 11.13) are sometimes used to seal off those perforations that are first to accept the fracturing fluid or acid. In this case, burr-free, round entry holes of consistent size are needed. So, for stimulation operations, the order of importance of the geometrical factors for perforating is 1. Perforation diameter 2. Shot density 3. Gun phasing and orientation 4. Perforation length

Stimulation Stimulation operations involve acidizing and hydraulic fracturing. The objective is to increase the size and number of paths by which fluid can flow from the formation to the wellbore. Both operations–acidizing and fracturing– require that large amounts of fluid be pumped under high pressure into the formation.

110

So, coincidentally, the order of importance of the perforating geometrical factors is identical for both FracPac operations.

Table 11.1 — Typical Underbalanced Pressure Differentials for Perforation Cleanup Underbalanced Differential

Underbalanced Differential

Formation Permeability

for Liquid Production

for Gas Production

High (100 md)

200 to 500 psi

1,000 to 2,000 psi

Low ( 100 md)

1,000 to 2,000 psi

2,000 to 5,000 psi

Well Conditions

Wellbore Fluids

Formation characteristics and completion objectives determine the perforating geometrical factors needed in a perforating system. Well conditions, on the other hand, usually determine the size and type of gun that can be run, which can also play a significant role in the effectiveness of perforating operations.

Muds and dirty fluids can plug perforations, so clean completion fluids should be used during perforating. Special conditions may require selecting a completion fluid to suppress clay swelling or to avoid the formation of precipitates, either of which can block the passage of fluids through the formation.

Well conditions that must be considered in a FracPac perforating job include the type, size, and condition of wellbore tubular goods and other hardware; the presence of obstructions or corkscrews in tubular goods; any wellbore deviations or doglegs; the quality of the cement bond between casing and formation; and the type and level of wellbore fluids. Total depth and bottomhole temperature should also be noted. Attention must also be given to any other conditions that could affect perforating operations. For example, derrick height can restrict the maximum through-tubing gun lengths that can be used.

If corrosive fluids, high temperatures, or high pressures are likely to be encountered, then hollow-carrier guns are preferred. These guns protect the charges and ensure reliable operation under harsh conditions. High wellbore temperatures require that special charges, detonators, and detonating cord be used.

Wellbore Hardware The size of the tubular goods and obstructions within them, such as landings and nipples, determine the maximum outside diameter (OD) of the gun that can be run. If there are corkscrews in the tubing or if there are any sharp deviations or doglegs in the well, then a wire or strip gun would be selected instead of a hollow-carrier gun. If a perforator’s performance under actual downhole conditions is to be estimated from API target data, then the well’s casing size, grade, weight, and yield strength must be known. If the tubular goods are in poor condition or if the cement bond is of poor quality, then a hollow-carrier gun would be desirable to protect the tubulars from any further damage. If a hollow-carrier gun cannot be used when these conditions are prevalent, then there should be liquid in the borehole to cushion the tubulars from the shock of the detonating charges.

Differential Pressure Fluid level in the borehole can be adjusted to give the differential pressure needed at the time of perforating. As discussed earlier, underbalanced perforating can result in cleaner perforations; however, excessively high underbalance is not generally recommended since it can result in formation damage. As Figure 11.11 demonstrated, there is a maximum underbalance above which little or no cleanup occurs. Excessively high underbalance can cause sanding or movement of fines and therefore can impede instead of improve flow into and through perforations. Table 11.1 gives underbalanced pressures recommended for perforation cleanup. The values shown depend on formation permeability and formation fluid. Low permeability zones require higher differentials to force the liquid through the formation pores. Gas zones also require higher differentials since gas has a much higher compressibility than oil and thus does not flow back as readily as oil after being compressed during perforation.

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Shale

For a new through-tubing completion, the tubular goods, packers, and other downhole equipment are also selected to allow passage of the largest diameter gun system possible. The use of full-open tools or monobore-type completions will allow the largest diameter perforating systems to be run under controlled differential conditions. On new wells, the casing program should call for a short joint of casing (a pup joint) to be placed near the bottom of the well (and below tubing, if tubing is to be run). This will provide an easily identifiable marker on the casing collar log needed to confirm the depth readings recorded by the perforating unit.

Sand

In older wells, gun selection must usually be tailored to existing borehole conditions. For example, there may be liners run in damaged casing or there may be permanent packers or tubular goods that cannot be changed without major expense. Both of these conditions can place severe restrictions on the size and type of gun that can be run. Similarly, if the wellbore is already exposed to high-pressure formations, perforating system selection may be limited and additional pressure control equipment may be required.

Gun Selection

Figure 11.14 — A perforating system that allows individual gun sections to be selectively fired is used to perforate widely separately zones on one trip into the well. In the scene depicted here, intervals A and B have already been perforated using the lower sections of the gun, and the gun is positioned to perforate interval C.

New Wells Versus Older Wells The freedom possible in gun selection depends heavily upon whether the perforating operation involves a new well or an older well. In the case of new wells, borehole conditions can often be tailored to the type of gun that is desired. For example, if FracPac operations are to be undertaken on a new well, then casing can be selected to allow the passage of the large-diameter hollow-carrier casing guns that will give the desired high shot densities and large entrance hole diameters. 112

Once formation characteristics, completion objectives, and wellbore conditions have been examined, an intelligent choice of perforating systems can be made. Table 11.2 lists the major categories of perforating guns and gives the main features and applications of each. Table 11.3 lists the important physical characteristics of these guns. Special assemblies are sometimes needed in FracPac and related operations that involve multiple-zone completions, squeeze cementing, and remedial work to establish flow or circulation.

Perforating Multiple Zones Hollow-carrier guns can be used to perforate multiple zones during a single trip into the well. Special Select Fire subassemblies placed between gun sections allow the sections to be fired individually. For example, as illustrated in Figure 11.14, the lowest section can be fired in one zone, the gun moved up, and the next section fired in another zone. If required by the application, the gun sections can be phased differently and have different shot densities. With strip and wire guns, multiple zones are perforated by using blank gun sections between the zones to be completed and then simultaneously firing all charges. Blank sections are gun sections containing no charges. Blank sections are not usually used with hollow-carrier guns.

Table 11.2 — Features and Applications of Hollow-Carrier Guns ThroughCasing

Tubing

Gun

Gun

✓

✓

Features Carrier protects charges from borehole environment.

Applications High-pressure wells High-temperature wells Wells containing corrosive fluids (H2S, CO2, acid)

✓

✓

Carrier protects casing and cement from shock of charge detonation.

Zone to be perforated is near oil-water contact. (minimizes possibility of water migration due to casing or cement damage) Well is to be fractured. (avoids casing splits that would prevent ball sealers from seating)

✓

✓

Carrier retains debris from charge cases.

Zone to be perforated is near oil-water contact. (minimizes possibility of water migration due to casing or cement damage) Well is to be fractured. (avoids casing splits that would prevent ball sealers from seating)

✓

✓

Gamma perforator combination is available.

Well has no correlation log available. (permits gamma correlation logging and perforating to be done on same trip in well)

✓

✓

Selective fire is available.

Wells with widely separated zones to be perforated (requires fewer trips downhole to perforate)

✓

✓

Spiral-jet carriers are available.

Squeeze cementing (increases probability that perforations intersect a channel) Hydraulic fracturing (increases probability that perforations intersect natural fractures)

✓

✓

High-shot-density carriers are available.

Gravel packing (reduces flow velocity through perforations when large-entry-hole charges are used) Sand control (prevents sanding when small-entry-hole charges are used, but permits adequate fluid flow for production when high perforation density is used) Hard formations (increases flow rates when large-entry-hole charges are used)

✓

Gun has small diameter.

High-pressure wells (Gun can pass through tubing.)

Table 11.3 — Features and Applications of Strip and Wire Guns Strip

Wire

Gun

Gun

✓

✓

Features Larger explosive load will pass through small restriction.

Applications Deep penetration is needed. Large entrance hole diameter is needed.

✓

✓

Flexible carrier

Well has dogleg or corkscrewed tubing.

✓

✓

Light weight

Long intervals are to be perforated on one run into well.

✓

✓

Economical carrier

Multiple zones are to be perforated. (Fewer trips are required with the long carriers; no charges are loaded over those carrier sections corresponding to intervals that are not to be perforated.)

113


Squeezing and Fracturing In some instances, a radial charge distribution denser than that provided by guns phased 90˚ or less is desired. For example, in hydraulically fracturing a naturally fractured reservoir, a high radial distribution of shots increases the chances of perforations intersecting natural fractures. Similarly, in squeeze cementing to eliminate channels, a high radial distribution of shots increases the chance of perforations intersecting channels and thus of cement being pumped into those channels.

Radial Distribution of Perforations When Spiral Phasing is Used

Halliburton’s Spiral Jet perforating guns provide the high radial shot density desired in these applications. These hollow-carrier guns have an effective 15˚ phasing over 6 ft of perforated interval. So, as Figure 11.15 shows, over a 6-ft interval, perforations from these guns extend out from the borehole in 24 directions.

Radial Distribution of Perforations When 90° Phasing is Used

Perforating Tubing and Drillpipe Figure 11.15 — Over a 6-ft interval, Spiral Jet perforating guns have an effective phasing of 15˚ and perforate in 24 directions. Perforations from a standard 90˚-phased gun extend out in only 4 directions.

Tubing Puncher charges use controlled penetration to perforate tubing or drillpipe without damage to the surrounding casing. Loaded in hollow-carrier throughtubing guns, these charges can be used to establish circulation when drillpipe is stuck. They also allow tubing or tailpipe below a packer to be perforated when the original tubing or nipple has become plugged. Additionally, tubing above a packer can be perforated to circulate sand from the top of the packer.

Ensuring Proper Gun Clearance

Cement Casing

Gun Perforation

Figure 11.16 — Decentralization is desired in 0˚-phased guns since this generally increases perforation length. However, for guns that are not phased at 0˚, decentralization causes variations in perforation length and diameter.

114

Proper clearance between the gun and the casing is necessary to obtain optimal charge performance. Clearance is associated with gun centralization or decentralization in the borehole. Figure 11.16 illustrates how charge performance can vary with variations in clearance. When hollow-carrier casing guns are run in the casing size for which they are designed, no centralization or decentralization is required since any variations in clearance around the gun will be minimal. However, if a such a gun is run in a casing size for which it was not designed, special care must be taken to centralize the gun in the wellbore. This ensures that perforation entry hole size and perforation length are uniform around the wellbore. With hollowcarrier through-tubing guns, if there is an appreciable difference between the gun’s OD and the casing’s inside diameter, the guns should be 0˚ phased and decentralized for maximum penetration and maximum entrance hole diameter. Magnetic and mechanical gun decentralizers are available for these guns.

CERTIFICATION DATA SHEET PERFORATING SYSTEM EVALUATION, RP 43, SECTIONS 1 and 2

API FORM

Explosive Weight ___________ gm, _________ powder, Case Material ___________________ AVAILABLE TO ALL 22.7 RDX STEEL Service Company ______________________________________________________ Max. Temp, F ______ 1 hr _______ 3 hr _______ 24 hr _______ 100 hr ______ ______ hr 4-1/2” THREADLESS GUN SYSTEM (TGS) 325 Gun OD & Trade Name _________________________________________________ Maximum Pressure Rating _____________ psi, Carrier Material _________________________ 4” DP 4,000 STEEL Charge Name _________________________________________________________ Shot Density Tested _____________________________________________________shots/ft C4500039 Date of Manufacture _____________ 7/11/92 4 Manufacturer Charge Part No. _____________ Recommended Minimum ID for Running _________________________________________in. RETRIEVABLE/EXPENDABLE/NON-SCALLOPED Gun Type ____________________________________________________________ Available Firing Mode _________________ Selective, ____________________ Simultaneous 90 Phasing Tested _______ degrees, firing Order X _____ Top Down, _______ Bottom Up Debris Weight ___________________ gm/charge, Debris ___________________ in.3/charge N/A Debris Description______________________________________________________ Remarks _____________________________________________________________________________________________________________________________________________

SECTION 1 – CONCRETE TARGET 7” 32 L80 AUGUST 21, 1992 Casing Data ____________ OD, Weight _______________ lb/ft, ________________ API Grade, Date of Concrete Test _____________________________________________________________ 48” 6,277 42 Target Data ____________ OD, Briquet Compressive Strength _____________ psi, Age of Target ________________________________________________________________________ days No. 7 No. 8 No. 9 No. 10 Shot No. No. 2 No. 3 No. 4 No. 5 No. 6 No. 1 0 0.41 0 0.41 0.89 Clearance, in. .............................................................................. 0.89 0.41 0.41 0.89 0.41 Casing Hole Diameter, Short Axis, in. . ....................................... 0.33 0.44 0.44 0.38 0.40 0.41 0.38 0.37 0.42 0.43 0.34 0.46 0.44 0.40 0.42 0.42 0.38 0.39 0.47 0.45 Casing Hole Diameter, Long Axis, in. ......................................... Average Casing Hole Diameter, in. ............................................. 0.34 0.45 0.44 0.39 0.42 0.42 0.38 0.38 0.45 0.44 16.95 13.78 14.65 17.45 15.95 18.55 18.55 14.15 19.65 19.65 Total Depth, in. ............................................................................ Burr Height, in. ............................................................................ 0.07 0.06 0.04 0.11 0.05 0.03 0.07 0.08 0.07 0.06 No.11 No.12 No.13 No.14 No.15 No.16 No.17 No.18 No.19 No.20 Average Shot No. ND 0.41 0.89 0.41 _____ _____ _____ _____ _____ 0.** Clearance, in. .............................................................................. 0 ND 0.41 0.46 0.42 0.40 _____ _____ _____ _____ _____ 0.41 Casing Hole Diameter, Short Axis, in. ........................................ Casing Hole Diameter, Long Axis, in. ......................................... ND 0.43 0.47 0.42 0.44 _____ _____ _____ _____ _____ 0.42 ND 0.42 0.47 0.42 0.42 _____ _____ _____ _____ _____ 0.42 Average Casing Hole Diameter, in. ............................................. Total Depth, in. ........................................................................... ND 15.65 19.15 14.05 16.85 _____ _____ _____ _____ _____ 16.73 ND 0.04 0.03 0.08 0.03 _____ _____ _____ _____ _____ 0.06 Burr Height, in. ........................................................................... Remarks ____________________________________________________________________________________________________________________________________________________

SECTION 2 – BEREA SANDSTONE CORE TARGET Berea Bulk Porosity, ________________ % Date of Berea Test _________________ %

Shot No. Faceplate Hole Diameter, Short Axis, in. ......................... Faceplate Hole Diameter, Long Axis, in. .......................... Average Faceplate Hole Diameter, in. ............................. Total Depth, in. .................................................................

No. 1 ______ ______ ______ ______

No. 2 ______ ______ ______ ______

No. 3 ______ ______ ______ ______

No. 4 ______ ______ ______ ______

No. 5 ______ ______ ______ ______

No. 6 ______ ______ ______ ______

Average ______ ______ ______ ______

CERTIFICATION Type of Certification: [X] Self

[ ] Third Party

I certify that these tests were made according to the procedures as outlined in API RP 43: Recommended Practices for Evaluation of Well Perforators, Fifth Edition, January 1991. All of the equipment used in these tests, such as the guns, jet charges, detonator cord, etc., was standard equipment with our company for use in the gun being tested, and was not changed in any manner for the test. Furthermore, the equipment was chosen at random from stock and therefore will be substantially the same as the equipment which would be furnished to perforate a well for any operator.

______ CERTIFIED BY X RECERTIFIED

(Company Officer)

EXPLOSIVES PRODUCTS MANAGER (Title)

(Date)

HALLIBURTON (Company)

2001 S. I-35 ALVARADO, TX. 76009 (Address)

Figure 11.17 — API data sheets give information for comparing the performance of different charges and for planning perforating operations.

COMPUTER-ASSISTED PERFORATING PLANNING Computer programs are available for selecting the perforating geometry that will give optimal flow characteristics for a particular application.

Perforating Planner Halliburton’s Perforating Planner uses API RP-43 data from surface tests to predict perforator performance at downhole conditions. The program can use the statistical variations in charge performance that occurs in API data to induce corresponding statistical variations in predicted

downhole performance. The mathematical model underlying the program accounts for such variables as casing grade, multiple casing strings, gun-to-casing clearance, gun eccentralization, casing eccentralization, wellbore fluid density, cement compressive strength, formation strength, and formation effective stress. The Perforating Planner provides detailed analysis of clearance effects on entrance hole diameters and penetration, and furnishes a clear diagram of the perforating system’s shot pattern. Figure 11.17 displays an API data sheet for a certain perforating system, and Figure 11.18 shows the Perforating Planner’s graphical representation of that data. Figure 11.19 depicts the downhole performance that the Perforating

115


Perforating Planner API RP 43 Section 1 Test Data: Phase Diagram Gun Description Mfgr: Jet Research Center Type: 4-1/2-in. threadless Part No.: C4500039 Powder: 23 gm RDX Phasing: 90° Shot Density: 4 spf Rotation: 90° Position: Eccentered Test Target Casing OD: 7.000 in. Casing Wt.: 32.00 lbm/ft Casing Grade: L-80 Target Type: Concrete Briquette Briquette Comp. Strength: 6,277 psi Surface Test Perf No. Penetration (in.) 1 17.93 2 16.31 3 16.68 4 15.75 Avg 16.73

Diameter (in.) 0.420 0.432 0.413 0.397 0.417

Figure 11.18 — Information from the API data sheet of Figure 11.17 was used in Halliburton’s Perforating Planner to profile the perforator’s typical test performance. Results are shown here and take into account the statistical variations in the data that were reported on the API sheet.

Perforating Planner Downhole Gun Performance: Phase Diagram Gun Description Mfgr: Jet Research Center Type: 4-1/2-in. threadless Part No.: C4500039 Powder: 23 gm RDX Phasing: 90° Shot Density: 4 spf Rotation: 270° Position: Eccentered Well Configuration Casing OD: 7.000 in. Casing Wt.: 32.00 lbm/ft Casing Grade: J-55 Borehole: 8.500 in. Fluid: 8 lbm/gal Damage: 2.000 in. Downhole Performance Rock Type: Sandstone Rock Comp. Strength: 1,323 psi Rock Porosity: 30% Perf No. 1 2 3 4 Avg

Penetration (in.) 19.11 17.37 19.11 17.74 18.33

Diameter (in.) 0.430 0.407 0.430 0.420 0.422

Figure 11.19 — The Perforating Planner also used the API data of Figure 11.17 to predict the perforator’s downhole performance under stated wellbore and formation conditions. Results are shown here. Statistical variations in API data were also considered as in the previous figure.

116

Perforating Planner Downhole Gun Performance: Casing Hole Phase Diagram Gun Description Mfgr: Jet Research Center Type: 4-1/2-in. threadless Part No.: C4500039 Powder: 23 gm RDX Phasing: 90° Shot Density: 4 spf Rotation: 270° Position: Eccentered Well Configuration Casing OD: 7.000 in. Casing Wt.: 32.00 lbm/ft Casing Grade: J-55 Borehole: 8.500 in. Fluid: 8 lbm/gal Damage: 2.000 in. Downhole Performance Rock Type: Sandstone Rock Comp. Strength: 1,323 psi Rock Porosity: 30% Perf No. 1 2 3 4 Avg

Diameter (in.) 0.430 0.407 0.430 0.420 0.422

Figure 11.20 — This closeup view generated by the Perforating Planner emphasizes how gun eccentralization affects perforation entrance hole geometry. The perforating system here is the same as that in Figure 11.17, and the casing parameters are the same as those in Figure 11.19.

Planner calculates could be typically obtained from that system under the specified borehole and formation conditions. Note that the downhole penetrations are significantly greater than the API target penetrations; this is largely due to the difference in compressive strength between the downhole formation and the API target. The slight difference in entrance hole diameters between the downhole performance and API target performance can be attributed to differences in casing characteristics. Figures 11.20 and 11.21 from the Perforating Planner focus on gun phasing and the resulting shot pattern for the same system. Figures 11.22 presents the Perforating Planner’s analysis of perforation entrance hole diameter as a function of clearance. Such information is particularly important when stimulating using gels with high sand concentrations. Figure 11.23 shows the similar analyses of perforation penetration as a function of clearance. Figure 11.24 is a Perforating Planning summary of program inputs and outputs related to the downholeperformance predictions that were illustrated in Figures 11.19 through 11.23.

Well Evaluation Model Halliburton’s Well Evaluation Model uses wellbore configuration, formation characteristics, reservoir parameters, and results from the Perforating Planner to predict inflow performance. In particular, the skins and associated pressure drops resulting from perforation, drilling fluid invasion, partial completion, well deviation, and gravel packing are nodally analyzed to determine flow rates. Figures 11.25 and 11.26 present graphical results from the model; Figures 11.27, 11.28, and 11.29 list alphanumeric program inputs and outputs associated with Figures 11.25 and 11.26. The following procedures are typically involved when applying the Well Evaluation Model: 1. An initial selection of a perforating system is made, based on the general perforating geometry criteria for the FracPac completion under consideration. 2. The Perforating Planner is used to determine the downhole performance of the perforator.

117


Perforating Planner Casing Shot Pattern 0

6

Gun Description Mfgr: Jet Research Center Type: 4-1/2-in. threadless Part No.: C4500039 Powder: 23 gm RDX Phasing: 90° Shot Density: 4 spf Rotation: 270° Position: Eccentered

8

Well Configuration Casing OD: 7.000 in.

Vertical Distance (in.)

2 4

10 12 0

45

90 135 180 225 270 Horizontal Distance (°)

315

360

Figure 11.21 — The Perforating Planner produces a two-dimensional representation of the perforating system’s shot pattern into the casing. The perforating system here is the same as that in Figure 11.17, and the casing OD is the same as that in Figure 11.19.

Perforating Planner Casing Hole Diameter Clearance Analysis

Casing Hole Diameter (in.)

0.50


0.45

Test Casing Casing OD: 7.000 in. Casing Wt.: 32.00 lbm/ft Briquette Comp. Strength: 6,277 psi

0.40

Well Casing Casing OD: 7.000 in. Casing Wt.: 23.00 lbm/ft

0.35 Section 1 Test Data Downhole Clearance Average of Test Data

Downhole Configuration Offset Angle: 270° Gun Position: Eccentered

0.30 0.0

0.5

1.0 Clearance (in.)

1.5

2.0

Note: All diameters are based on L-80 casing.

Figure 11.22 — This graph created by the Perforating Planner compares perforation entrance hole diameter with gun clearance. The diameters corresponding to the two downhole clearances are those that would be obtained if the perforating system were shot in the same grade of casing as the test casing. The perforating system is the same as that in Figure 11.17.

118

Perforating Planner Penetration Clearance Analysis

18


16

Test Casing Casing OD: 7.000 in. Casing Wt.: 32.00 lbm/ft Briquette Comp. Strength: 6,277 psi

14

Well Casing Casing OD: 7.000 in. Casing Wt.: 23.00 lbm/ft

20

e

Total Target P netration (in.)

22

Section 1 Test Data Downhole Clearance Average of Test Data

12 0.0

0.5

1.0 Clearance (in.)

Downhole Configuration Offset Angle: 270° Gun Position: Eccentered

1.5

2.0

Figure 11.23 — This Perforating Planner graph shows the relationship between perforation penetration and gun clearance. The penetrations corresponding to the two downhole clearances are those that would be obtained if the perforating system were shot in the same grade of casing as the test casing. The perforating system is the same as that in Figure 11.17.

3. In the Well Evaluation Model, the perforator’s downhole performance is used along with wellbore and reservoir characteristics to estimate bottomhole flowing pressures for a suitable range of flow rates.

7. From the perforating systems analyzed, the one that best suits overall job requirements for such parameters as flow rates, pressure drops, and critical sanding pressures is selected.

4. The Well Evaluation Model is applied to the results from Step 2 to generate an Inflow Performance Relationship (IPR) curve.

The Well Evaluation Model assists in designing a FracPac job by allowing the completion engineer to identify parameters such as completion interval, perforation geometry, tubular specifications, and gravel pack requirements that will give the preferred flow characteristics. Pore pressure and critical sanding pressure are determined from Halliburton’s STRESS Analysis Module (See Chapter 6) and are considered when selecting the various parameters for the preferred flow.

5. For a given wellhead pressure, the Well Evaluation Model is used to determine the intake pressures at tubing bottom for various flow rates. These values are included on the IPR chart as a Tubing Intake curve. The intersection of the Tubing Intake and IPR curves gives the estimated flow rate and bottomhole flowing pressure for the completion with the given perforating geometry and wellhead pressure. 6. Steps 1 through 5 are repeated with other perforators that satisfy the general perforating geometry requirements of the job.

With regard to gravel-packed, unstimulated completions, knowledge of the critical value of drawdown pressure at which sanding might occur is crucial, as is knowledge of the pore pressure. With the Well Evaluation Model results, the completion can be optimized to obtain maximum production and to maintain pressures below critical values.

119


PERFORATING PLANNER DATA SUMMARY Gun Identification Service Company ...............................Jet Research Center, Inc. Trade Name........................................4-1/2-inch Threadless Gun Charge Name .....................................4-inch DP Part Number.......................................C4500039

Gun Type ..............Retrievable/Expendable/Non-Scalloped Gun Diameter .......4.500 in. Explosive Weight ...22.7 g Powder .................RDX

Well Configuration Rock Type.................................................................Sandstone Reservoir Pressure (psig)............................................2,999.0 Porosity (%)..............................................................30.0 Effective Stress (lbm/ft) .............................................2,000 Compressive Strength (psi) .......................................1,323 True Vertical Depth (ft) .............................................5,000 Drillbit Diameter (in.) ................................................8.500

Centralized Casing ...................................................Yes Hole/Casing Standoff (in.).........................................0.750 Number of Casings...................................................1 Completion Fluid Density (ppg).................................8.00 Casing OD (in) ..........................................................7.000 Casing Weight (lbm/ft) .............................................23.000 Casing Grade ...........................................................J-55

Downhole Gun Configuration Shot Density (spf) .....................................................4.0 Phasing (˚) ................................................................90 Gun Position ............................................................Eccentered

Charge Pattern.........................................................Spiral Gun Rotation (˚) .......................................................270.0

Predicted Downhole Gun Performance Plane

Clearance* (in.)

Rock Penetration (in.)

Casing Hole Diameter (in.)

Casing/ Cement (in.)

Casing 1

Casing 2

Casing 3

1

0.793

19.108

0.430

na

na

1.103

2

0.000

17.370

0.407

na

na

1.067

3

0.793

19.108

0.430

na

na

1.103

4

1.866

17.743

0.420

na

na

1.067

18.332

0.422

Average

* Maximum clearance in API Section 1 Test is 1.5940 in.

Figure 11.24 — The Perforating Planner furnishes a report that identifies the gun system, describes the well configuration, states the downhole gun configuration, and lists the predicted downhole performance of the gun.

120

Well Evaluation Model Nodal Analysis

Well Evaluation Model Nodal Analysis

Pressure Drop vs Liquid Flow Rate

Formation Pressure Drop

Pressure Drop (psi)

80 60

Perforation Diameter Perforation Length Shot Density Gun Phasing

Flowing Bottomhole Pressure vs Liquid Flow Rate Variable 7.0 in. 8 spf 45°

Perforation Pressure Drop (0.5-in. perforation diameter)

40 20

4,000 Inflow Performance Relationship (0.7-in. perforation diameter)


100

Perforation Pressure Drop (0.7-in. perforation diameter)

0

3,000

Inflow Performance Relationship (0.5-in. perforation diameter)

2,000

Tubing Intake

1,000

Perforation Diameter Perforation Length Shot Density Gun Phasing

Variable 7.0 in. 8 spf 45°

0 0

2,000 4,000 Liquid Rate (BLPD)

6,000

Figure 11.25 — Halliburton’s Nodal Analysis Module performs an in-depth analysis of reservoir, fluid, wellbore, and completion properties to predict flow rates and pressure drops. Comparison of data from different completion configurations allows a completion design to be selected that will minimize or eliminate sanding and will permit proper management of reservoir pressures for optimal production. Assumptions and results used in generating the graph in this figure are shown in Figures 11.27, 11.28, and 11.29.

0

2,000 4,000 Liquid Rate (BLPD)

6,000

Figure 11.26 — Besides examining the relation between flow rate and pressure drop, the Nodal Analysis Module predicts flowing bottomhole pressure as a function of flow rate. For the tubing characteristics assumed in the completion design, the intersection of the Tubing Intake curve and an Inflow Performance Relationship curve gives the predicted flowing bottomhole pressure and flow rate that will result for the given completion design. Assumptions and results used in generating the graph in this figure are shown in Figures 11.27, 11.28, and 11.29.

NOMENCLATURE CFE = core flow efficiency

Sg = gravel-pack skin

Df = turbulent flow coefficient for formation

Sor = residual oil saturation

Dg = turbulent flow coefficient for gravel pack

Sp = perforation skin

Dp = turbulent flow coefficient for perforation

St p = two-phase (gas/oil) skin

kc = permeability in perforation crushed zone kd = permeability in wellbore-damaged zone ku = permeability in undisturbed formation PR = productivity ratio Q = liquid flow rate S = total skin Sc = partial completion skin

Swirr = irreducible water saturation WFE = well flow efficiency

REFERENCES 1. An Introduction to Perforating, Halliburton, Houston, 1986. 2. Locke, S.: “An Advanced Method for Predicting the Productivity Ratio of a Perforated Well,” 1980 SPE Annual Symposium on Formation Damage Control, Bakersfield, California, January 28-29. 3. Bell, W.T.: “Perforating Underbalanced—Evolving Techniques,” JPT (October 1984) 1653-1662.

Sd = damaged-zone skin 121

FRACPAC COMPLETION SERVICES WELL EVALUATION MODEL INPUT SUMMARY Fluid Properties Mole Percent CO2 (%) ......................................0.00 Bubble Point @ 160˚F (psig) ..............................1,785.8 Oil Volume Factor Correction............................Vazquez/Beggs Solution Gas Correction....................................Vazquez/Beggs Oil Viscosity Correction.....................................Ng/Egbogah Oil/Water Viscosity Correction ..........................Avg Gas-Water Solubility .........................................No

Oil Gravity (˚API) ...............................................35.00 Gas Gravity (air = 1.0).......................................0.800 Water Gravity (water = 1.0) ..............................1.060 Produced GOR (scf/bbl).....................................400.0 Percent Water (%)............................................0.0 Mole Percent N2 (%).........................................0.00 Mole Percent H2S (%).......................................0.00

Wellbore Data Flowing Wellhead Pressure (psig) ......................250.0

Flowing Wellhead Temperature .......................Heat Tran Casing/Tubing Description

Measured Depth (ft) ......................................6,000.00 Vertical Depth (ft) ..........................................6,000.00 Vertical Deviation (˚) .......................................0.0 Casing OD (in.) ..............................................7.000 Casing ID (in.) ................................................6.366 Tubing OD (in.) ..............................................2.875

Tubing ID (in.) ................................................2.441 Flow Path ......................................................Tubing Flow Correlation ............................................Hagedorn/Brown Absolute Roughness (in.) ...............................0.00180 Perforating Depth, Measured (ft) ...................6,000.0 Perforating Depth, TVD (ft) ............................6,000.0 Heat Transfer Model Heat Transfer Coefficient (BTU/hr/ft2/˚F) ............2.292 Slip Factor ........................................................1.00

Measured Depth (ft) .........................................6,000.00 Static Temperature (˚F)......................................160.0

Reservoir Description Flow Model.....................................................Radial Formation Permeability (md)............................1,000.000 Net Stratigraphic Pay (ft) .................................10.0 Measured Net Pay (ft)......................................10.0 Reservoir Pressure (psig) ..................................4,000.0 External Drainage Radius (ft) ...........................1,200.0 Drill Bit (in.) .....................................................10.625 Reservoir Laminar Skin ....................................Theory Horizontal/Vertical Permeability Ratio ..............5.0

Damaged-Zone Permeability Ratio, kd /ku .........0.4 Damaged-Zone Thickness (in.).........................2.00 Reservoir Turbulence, D (d/bbl)........................Theory Reservoir Turbulence, Beta (1/ft)......................0.5812406E+07 Oil/Gas Flow....................................................Vogel Oil/Water Flow ................................................Segregated Rock Type .......................................................Sandstone Relative Permeability to Oil @ Swirr ...................0.80 Relative Permeability to Water @ Sor ................0.2

Completion Data (Perf + Pack) Measured Peforated Interval (ft)........................10.0 Formation Top to Perforation Top (ft) ...............0.0 Gun Phasing (˚) .................................................45 Perforation Density (spf) ...................................8.00 Perforation Diameter (in.) .................................0.700 Perforation Length (in.).....................................7.0 Crushed-Zone Thickness (in.) ............................0.50 Crushed-Zone Permeability Ratio, kc /ku ............0.30

Crushed-Zone Turbulence Option .....................Dmg*Crush Crushed-Zone Turbulence, Beta (1/ft) ...............0.3093279E+08 Casing/Cement Thickness (in.) ..........................2.13 Tunnel Calculation Method ..............................Casing ID Tunnel Length (in.) ...........................................2.629 Gravel Permeability (md)...................................40,000 Turbulence Coefficient Method ........................Saucier Turbulence Coefficient (1/ft) .............................0.1006400E+06

Figure 11.27 — The Nodal Analysis Module uses extensive fluid, wellbore, reservoir, and completion information in making its flow and pressure estimates. The data shown here were used in calculations to generate the graphs in Figures 11.25 and 11.26.

122

WELL EVALUATION MODEL IPR / TUBING-INTAKE REPORT IPR CURVE 1 Perforator Parameters Perforation Diameter (in.) .................................0.7 Perforation Length (in.).....................................7.0

Shot Density (spf) .............................................8.0 Gun Phasing (˚) .................................................45.0 IPR Pressure Drop Summary

Liquid Rate (BLPD)

Formation Pressure Drop (psi)

Perforation Pressure Effect (psi)

Gravel Pack Pressure Drop (psi)

____________________

Flowing Bottomhole Pressure at Producing Depth (psig) ____________________

____________________

____________________

____________________

1,500 2,000 2,500 3,000 3,500 4,000 4,500 5,000 5,500 6,000

3,668.09 3,526.79 3,370.16 3,198.18 3,010.81 2,808.03 2,589.74 2,355.84 2,106.16 1,840.49

209.4 279.5 349.8 420.3 490.9 561.7 632.7 703.8 775.1 846.5

11.2 15.3 19.7 24.4 29.2 34.3 39.7 45.2 51.0 57.0

111.3 178.3 260.3 357.1 469.0 595.9 737.9 895.2 1,067.8 1,256.0

Absolute Openhole Flow Potential (BLPD) ..........9,056.289

Completion Skin Analysis Flow Rate

Near-Wellbore Skin

Perforation Skin

Gravel Skin

Total Skin

Q

Sc

Sd

Stp

Df*Q

Sp

Df*Q

Sg

Db*Q

1,500.0

0.0

0.48

0.00

0.03

0.370

0.038

1.610

2.622

515

2,000.0

0.0

0.48

0.00

0.04

0.370

0.051

1.610

3.549

6.10

2,500.0

0.0

0.48

0.00

0.04

0.370

0.063

1.610

4.509

7.08

3,000.0

0.0

0.48

0.00

0.05

0.370

0.076

1.610

5.503

8.09

3,500.0

0.0

0.48

0.00

0.06

0.370

0.088

1.610

6.535

9.15

4,000.0

0.0

0.48

0.00

0.07

0.370

0.101

1.610

7.609

10.24

4,500.0

0.0

0.48

0.00

0.08

0.370

0.114

1.610

8.728

11.38

5,000.0

0.0

0.48

0.00

0.09

0.370

0.126

1.610

9.892

12.57

5,500.0

0.0

0.48

0.00

0.10

0.370

0.139

1.610

11.105

13.80

6,000.0

0.0

0.48

0.00

0.11

0.370

0.152

1.610

12.367

15.09

Q......................Flow Rate (BLPD) Sc .....................Skin, Partial Completion Sp .....................Skin, Perforation Sg .....................Skin, Gravel Pack

Stp ....................Skin, Two-Phase Gas/Oil Sd .....................Skin, Damaged Zone S.......................Skin, Total

S

Df*Q.................Turbulence, Formation Dp*Q ................Turbulence, Perforation Dg*Q ................Turbulence, Gravel Pack

Figure 11.28 — The data in the previous figure and the perforator parameters shown here were used to generate an IPR pressure drop summary and an associated completion skin analysis. IPR results are plotted in Figures 11.25 and 11.26.

123

FRACPAC COMPLETION SERVICES WELL EVALUATION MODEL IPR / TUBING-INTAKE REPORT IPR CURVE 2 AND TUBING-INTAKE CURVE Perforator Parameters Perforation Diameter (in.) .................................0.5 Perforation Length (in.).....................................7.0

Shot Density (spf) .............................................8.0 Gun Phasing (˚) .................................................45.0 IPR Pressure Drop Summary

Liquid Rate (BLPD)

Formation Pressure Drop (psi)

Perforation Pressure Effect (psi)

Gravel Pack Pressure Drop (psi)

____________________

Flowing Bottomhole Pressure at Producing Depth (psig) ____________________

____________________

____________________

____________________

1,500 2,000 2,500 3,000 3,500 4,000 4,500 5,000

3,424.66 3,116.38 2,749.78 2,324.47 1,839.65 1,293.79 683.89 64.63

209.4 279.5 349.8 420.3 490.9 561.7 632.7 703.8

19.3 26.3 33.8 41.7 49.9 58.5 67.5 76.8

346.7 577.7 866.5 1,213.5 1,619.5 2,086.0 2,616.0 3,154.8

Absolute Openhole Flow Potential (BLPD) ..........5,065.555

Completion Skin Analysis Flow Rate

Near-Wellbore Skin

Perforation Skin

Gravel Skin

Total Skin

Q

Sc

Sd

Stp

Df*Q

Sp

Df*Q

Sg

Db*Q

S

1,500.0

0.0

0.48

0.00

0.03

0.642

0.060

3.155

10.253

14.62

2,000.0

0.0

0.48

0.00

0.04

0.642

0.080

3.155

14.038

18.43

2,500.0

0.0

0.48

0.00

0.04

0.642

0.100

3.155

18.084

22.51

3,000.0

0.0

0.48

0.00

0.05

0.642

0.120

3.155

22.432

26.88

3,500.0

0.0

0.48

0.00

0.06

0.642

0.140

3.155

27.117

31.60

4,000.0

0.0

0.48

0.00

0.07

0.642

0.160

3.155

32.158

36.67

4,500.0

0.0

0.48

0.00

0.08

0.642

0.180

3.155

37.536

42.07

5,000.0

0.0

0.48

0.00

0.09

0.642

0.201

3.155

39.968

44.54

Q......................Flow Rate (BLPD) Sc .....................Skin, Partial Completion Sp .....................Skin, Perforation Sg .....................Skin, Gravel Pack

Stp ....................Skin, Two-Phase Gas/Oil Sd .....................Skin, Damaged Zone S.......................Skin, Total

Df*Q.................Turbulence, Formation Dp*Q ................Turbulence, Perforation Dg*Q ................Turbulence, Gravel Pack

Producing Rates IPR Curve Tubing Intake Curve

Producing Rate (BLPD) at Intersection with IPR Curve

1

2

4,972.3

3,377.7

Figure 11.29 — The data in Figure 11.21 and the perforator parameters shown here were used to generate an IPR pressure drop summary, a completion skin analysis, and Tubing Intake curve information. IPR results are plotted in Figures 11.25 and 11.26, and Tubing Intake results in Figure 11.26. 124

Chapter 12 INTRODUCTION This chapter focuses on the various methods used to complete high-permeability formations. Completion methods depend on formation type; therefore, the discussion of completions is divided into formations with high, moderate, and no sanding tendency. These formations can be treated with gravel-pack or FracPac, OptiPac, and OptiFrac applications.

concerns of performing a gravel-pack treatment, FracPac treatment, or both, including wellbore conditions, workstring considerations, sand and screen selection, service tools, gravelpack packers, and sump packers. The many applications that are possible for high-sanding-tendency formations are also discussed.

COMPLETIONS FOR HIGHSANDING-TENDENCY FORMATIONS (FRACPAC)

Wellbore Conditions

Gravel-pack techniques and systems have come a long way from the days of simply running a slotted liner into the well and dumping sand down the annulus. Pumping systems, circulating valves, packers, screens, and other gravel-pack placement tools have evolved into systems that perform all of the gravelpack and fracturing procedures in a single trip of the workstring. In addition to quick deployment, the downhole equipment used must withstand the increased forces exerted during high-rate gravel-packing and fracturing treatments. Halliburton has developed some of the most cost-effective, reliable completion equipment in the industry and has recently developed the HIGH-RATE downhole tool system for gravel-pack and FracPac completions in 5-inch and 5-1/2-inch casing sizes. Efficient fluids have been developed for effective delivery of proppant into the fractures, perforations, and annuluspack area. These fluids are designed to enhance cleanup after fracturing and packing operations are completed. The following sections focus on the many

Well Completions

When designing a gravel-pack or FracPac completion, several considerations are critical to the safety of the well and to the efficiency of the completion. Casing size, weight, and grade should be identified, along with the workstring and tubing size, weight, grade, and thread type. The depth that the downhole components will be set, the presence of H2S or CO2 in the produced effluents, bottomhole temperature, bottomhole pressure, completion fluid, and well deviation will determine the type of downhole components that can be used. Perforation depth, density, and phasing, along with remedial cement-squeezed areas in the well should also be known. The forces encountered during the gravel-pack and FracPac job place substantial forces on the workstring. Fluid pressure and temperature changes inside and outside of the workstring during circulating and injection can cause piston, friction, balloon, thermal, and buckling effects to occur. These effects can be pronounced and should be anticipated when selecting the downhole tool systems and techniques to be used. Halliburton and other companies have developed numerous

125


All-Welded, Wire-Wrapped Screen

pieces of software specifically designed to calculate the forces exerted on the workstring during gravel-pack and FracPac pumping applications.

Workstring Considerations

Figure 12.1 — All-welded, wire-wrapped screens are an industry standard. The wire that wraps the vertical ribs is keystone shaped to avoid plugging with sand. Well conditions determine exact metallurgy required, but the standard screen is stainless-steel screen on carbon-steel base pipe.

Perforated Prepack Screen

Figure 12.2 — Perforated prepack screens have an inner screen and an outer perforated case. Epoxy-coated, thermally set gravel is placed in the annulus between the inner screen and outer case. The primary application for this type of screen is in open hole with no sand pumped as an annular pack.

126

The workstring used for FracPac and gravel-pack completions should be selected based on hole depth and angle, packer bore size, set-down weight requirements, overpull requirements, and workstring OD to casing ID. The workstring should be cleaned internally and externally before it is run into the well. All threaded connections should be inspected, and pipe dope should be applied to the pin (male) joints. The workstring should be degreased with a caustic solution and pickled with acid before gravel packing to remove any pipe dope, oil, mill scale, and rust from the internal surfaces. Workstring sizes larger than 3-1/2 inches can create slurry pumping problems.

Sand and Screen Selection The primary goal of gravel packing is to prevent the production of formation sands without limiting the flow of hydrocarbon to the wellbore. Proper sizing of the gravel and its inherent pore space is the most important decision made concerning the gravel pack. Formation samples are put through a sieve analysis to determine particle size. With the formation particle size identified, a proper size of pack gravel can then be chosen. Through tests that were performed to identify the optimum grain size for gravel packs, it was determined that average grain size of the pack gravel should be 5 to 6 times the formation sand size at the 50 percentile (median) point of the sieve analysis.1 This ratio of 5 to 6 times the formation sand size appears to provide absolute stoppage of formation sand flow into or through the gravel-pack medium. A more detailed discussion of sand is presented in the proppant and proppant selection chapter (Chapter 10). For FracPac applications, where conductivity within the fracture is important, larger sand sizes have been used successfully. Screened portions of the tubing string provide an entrance for incoming oil production while at the same time retaining the gravel pack. The wire spacing on the screen should be narrower than the smallest sand selected for the gravel pack. For optimum performance in a cased hole, the screen OD should have 1 inch of radial clearance from the casing ID. In an open hole, the screen OD should have 2 inches of radial clearance from the borehole wall.

Maintaining these clearance criteria helps eliminate gravel bridging in the annulus and makes a washover easier if a remedial workover becomes necessary. Refer to Figure 12.1 through Figure 12.4 for the various types of screens used in gravel-pack and FracPac completion services. In most applications, the wire-wrapped screen shown in Figure 12.1 is used, but in some angled wells and in wells where customer preference or special requirements arise, prepacked screens such as those shown in Figures 12.2 through 12.4 are placed. Centralized blank pipe is normally used to extend from the top joint of screen to the bottom of the gravel-pack tool assembly. Each joint of blank pipe should be centralized the same way as the screened sections. The collars used with blank pipe should be lathe-turned and beveled to help eliminate flow turbulence, ease running into a liner top, and ease washover during a remedial workover. The grade of blank pipe selected must withstand maximum collapse forces exerted during gravel-pack sandout and FracPac operations. The use of high-yield grades of blank pipe is mandatory on FracPac completions. Gravel-pack screens should be centralized every 15 ft. Welded blade-type centralizers are commonly used in cased hole applications; however, centralizers are now available that are welded to small spacers in the screen jacket. These smaller spacers provide more flow area across the screen surface by not requiring blank pipe for welded attachment. Screens that are used in openhole gravel-pack completions should have bow-spring centralizers installed at 15-ft intervals.

Special Clearance Prepack Screen

Figure 12.3 — Special clearance prepack screens are used when the ID and OD requirements of a standard, non-prepacked screen are needed. These screens have an inner microscreen and a standard outer screen, with gravel in the space between them. The gravel can be uncoated or epoxy coated and is much thinner than other prepack screens.

Dual-Screen Prepack

Cased-hole screened intervals should include up to 5 ft of overlap below the perforated zone and a minimum of 5 ft above the perforated zone. This additional screened area allows for inaccuracies in depth measurement and provides additional gravel reserves above the producing zone to compensate for any natural settlement of the gravel pack. Before any screen is run into the well, it should be checked to ensure that it is the correct gauge by inserting a feeler gauge into the openings of the screen. Verify that the base pipe inside the screen has been drilled by flushing water through each joint of screen. This water flush also helps wash out any debris left from manufacturing processes and debris that may have collected during shipment. Visually inspect each joint of screen to make sure it was not damaged during shipment. Check each joint of screen and blank to verify that each is still within drift (straightness) tolerances.

Figure 12.4 — The dual-screen prepack has two screens. A gravel layer is placed between a standard inner screen and a standard outer screen. The prepack provides gravel-pack type filtering when gravel packing is not feasible, or when special sand control is required.

127


DOWNHOLE TOOL SYSTEMS

Accessories for the Multiposition Tool

Downhole tool systems for gravel-pack and FracPac Completion Services are versatile in configuration and perform multiple functions. Halliburton’s standard multiposition tool system can be combined with numerous specialty subs, screens, blanks, liners, and packers to perform any of the FracPac Completion Services required. This system is especially attractive to operators because of the rig time savings provided by running and setting the screen assembly and performing the fracturing and gravelpacking portions of the FracPac procedure in a single trip of the workstring.

Accessories for the multiposition tool are available to allow positive indication of all service tool positions. For FracPac applications, normally the circulating and reverse positions are indicated.

Multiposition Service Tool The multiposition service tool is at first used to set the completion packer, and then directs fluid flow for the toolstring. Depending upon the type of job being performed, the multiposition tool can have either three or four positions. These positions are squeeze, circulating, upper circulating, and reverse. Each of these positions is discussed later in this chapter, based on the type of application being performed. The multiposition tool service tool has two exit ports, phased 180° apart for the 5-inch and 5-1/2-inch tool sizes. For larger tool sizes, the multiposition tool has three ports phased 120° apart. These multiple-exit-port designs allow for large flow area, which diffuses fluid flow to prevent tool erosion. Table 12.1A in the appendix at the end of this chapter lists the flow rates for all available multiposition tool sizes. Two alternate service tool configurations are available. The first is a “weight-down” version that eliminates the need to manipulate the workstring to establish the squeeze or circulating positions. By applying weight down on the packer, workstring contraction caused by thermal forces, balloon forces, and tool movement during pumping is negated. Additional set-down weight can be added as required during the job. The weight-down multiposition tool requires that the casing above the packer be able to withstand the high pressure exerted during the gravel-pack sandout or FracPac job. The second service tool configuration is the HIGH-RATE service tool. The HIGH-RATE service tool also uses the weight-down feature mentioned earlier. Throughput flow area has been increased to maximize pumping-rate capability and reduce erosion of the tool. This tool is available for use in 5-inch and 5-1/2-inch casing sizes.

128

Gravel-Pack Packers The VERSA-TRIEVE® retrievable packer or the PERMA-SERIES permanent packer can be deployed with the multiposition tool and can function as the gravel-pack packer, fracturing packer, and production packer. Packer sizes range from 4-1/2 inches to 10-3/4 inches. Both packers are available with various top sub configurations. Refer to Table 12.2A and Table 12.3A in the appendix at the end of this chapter for the complete ranges and specifications of available VERSA-TRIEVE and PERMA-SERIES packers.

Sump Packers In addition to the tool-system components already discussed, sump packers are typically used in combination with multiposition tools. The sump packer is usually set with electric wireline and is normally considered a permanent installation. The packer is set below the perforations and is used for depth correlation of the production screen to the perforated interval. A sump-packer seal assembly is attached to the bottom of the production screen, and the screens are then configured as needed for the well conditions. The workstring is run into the hole until the sump-packer seal assembly engages into a receiving bore in the sump packer. A collet guide is used to provide a positive snap engagement that is felt at the surface and verifies that the seal assembly is fully engaged with the sump packer. The sump that is created below the sump packer provides a trap for debris that settles after perforating and for lost tools to fall through. Also, the sump allows logging tools to be lowered past the perforations so that the entire interval can be surveyed for future operations. Refer to Table 12.3A in the appendix at the end of this chapter for the full range of available sump packers for use with the multiposition tool system.

Applications The multiposition service tool system can be configured with numerous combinations of subs, screens, blanks, and packers to form any of the following systems: • Single-zone FracPac System and gravel-pack system • Stacked (multiple-zone)FracPac and gravel-pack system • Washdown system

succession up the hole. As many as five zones have been packed and produced individually within a single wellbore. When one zone is depleted, a bridge plug is set to isolate the depleted zone. The bridge plug is usually set in a landing nipple that was run as part of the concentric production string. Once the plug is set, either a sliding side door device may be shifted or the concentric string can be perforated to establish flow communication with the formation.

• One-trip perforation and pack system • Absolute isolation system

Dual-Zone Completion

• Horizontal system

Another multi-zone completion is when dual zones are completed and produced separately. See Figure 12.7 for a schematic of a dual-zone completion. A sealbore is placed as part of the lower-zone production seal assembly. This sealbore and its accompanying seal unit isolates the lower production zone during FracPac and gravel-pack procedures. Production from the lower zone flows up the long-string production tubing while flow from the upper zone flows between the OD of the long string and the ID of the upper gravel-pack packer. Upper zone flow then continues up the short-string production tubing.

• Single-trip, multi-zone system • High-rate, high-pressure FracPac system • Slimhole system • Floater system

Single-Zone FracPac and Gravel-Pack System The multiposition service tool has four positions. Three positions are used to pump a FracPac job, and a fourth position is commonly used to pump long, high-density gravel-pack intervals. The positions used in a FracPac application are squeeze, circulate, and reverse. Positions used for a gravel-pack application are squeeze, lower circulate, upper circulate, and reverse. Refer to Figure 12.5 for a schematic and discussion of the pumping stages of a single-zone FracPac application.

Multi-Zone FracPac and Gravel-Pack Systems Selective Zone Completion Many variations of multi-zone FracPac and gravel-pack applications are possible. The most common applications are selective-zone completions and dual-zone completions. A selective FracPac and gravel pack may be applied when two or more zones have been completed and one of the zones is produced through a single string of tubing. Refer to Figure 12.6 for a schematic of a selective-zone completion. Normally the lower zone is produced first, and the remaining zones are produced in

Washdown System The multiposition tool is available in the washdown version( Figure 12.8). When the washdown multiposition tool is used, a washdown shoe is added to the bottom of the screen assembly. This tool configuration allows formation fines and debris to be removed from the wellbore before placing the gravel-pack or FracPac treatment.

One-Trip Perforate and Pack System (FracPac Optional) The one-trip perforate and pack system provides the versatility and time savings of running a perforating assembly with a retrievable gravel-pack packer/production packer in a single trip. Refer to Figure 12.9 for a schematic of the one-trip perforate and pack system. This system should be used to perforate intervals up to 50 ft long with well deviation angles less than 45°. At deviation angles over 45°, spent perforating equipment and debris may not fall completely to the bottom of the well, making operations difficult.

129


FracPac Circulate

FracPac Squeeze Position

Gravel Pack Packer

Screen

Sump Packer

FracPac Reverse

Gravel Pack Packer

Screen

Sump Packer

Figure 12.5 — The FracPac workstring in squeeze position varies little from the multiposition service tool configuration used to pump gravel packs. The standard multiposition service tool and flow subs have been upgraded to allow for high-pressure, high flow rate slurries. The slurry is squeezed into perforations and fractures, until the proppant fills in to the wellbore, when screenout occurs. The FracPac workstring in circulate position allows returns to be taken back to the surface. For FracPac service, the blank liner must be able to withstand exerted FracPac squeeze pressures. In circulating position, the flowback rate can be controlled to achieve a tight annular pack. The FracPac workstring in reverse position allows pump pressure to be applied down the annulus, and returns to be taken up to the surface in the workstring. On a standard FracPac string, the workstring is raised approximately 9 ft to actuate the reverse position. The formation is isolated (not totally) from the pump pressure by the reverse ball-check shown in red.

130

FracPac Selective-Zone Completion

FracPac Dual-Zone Completion

Dual Hydraulic-Set Packer Gravel-Pack Packer Gravel-Pack Packer

Upper Screen Upper Screen

Lower Screen Lower Screen

Sump Packer Sump Packer

Figure 12.6 — The FracPac workstring can be configured for selective-zone completion. The lower zone is normally produced first with successive zones up the hole produced subsequently. This allows lower, depleted zones to be plugged back. As many as five zones in a single wellbore have been individually packed and produced.

Figure 12.7 — The FracPac workstring can be configured for a dual-zone completion. The lower zone is produced up the long-string production tubing, and the upper zone is produced between the OD of the long string and the ID of the gravel-pack packer.

131


Wash Down/ Fluid Conditioning

Circulating/ Packing Position

Circulating (Preperforating) Position From the bottom up, the components of the one-trip perforate and pack system are the perforating guns, automatic-release drop-bar firing head or pressureactivated firing head, reciprocation-set packer (without an integrated equalizing bypass), bypass valve, lower O-ring sub or seal sub, tell-tale screen, O-ring sub, production screen, blank, ceramic flapper valve, and the retrievable gravel-pack assembly. A radioactive marker (RA tag) is normally run one joint above the multiposition service tool. This marker provides a stimulus for the gamma-ray depth correlation tool that is later run on wireline.

Perforating Position The downhole assembly previously discussed is run to the desired depth. Wireline is then run through tubing to provide positive depth correlation. The assembly, with the aid of the wireline correlation, is spaced across the zone of interest and the reciprocation-actuated GO packer is set. The bypass valve above the GO packer is opened and diesel or nitrogen is pumped to displace the packed-off area and provide the desired pressure for underbalanced perforating. The bypass valve is then closed to isolate the annulus above the GO packer. When the downhole environment is ready, a drop bar is dropped down the tubing to fire the perforating guns. Upon firing, the guns are released and fall to the bottom of the hole. A predetermined amount of formation fluids are produced to clean the perforation tunnels. The bypass valve is then reopened and the hydrocarbons are flowed out of the tubing. Before retracting the GO packer the bypass valve is shut and pressure is applied to the annulus. This annular pressure opens the annular bypass valve while rig pull is applied to release the GO packer. The annular-pressure-operated bypass valve prevents a possible fluid lock from occuring in the system. After the GO packer releases, the entire assembly is lowered until the screen is properly positioned across the perforated interval. Then, the GO packer is reset and the gravel-pack packer is set. The downhole tool assembly is now ready for the gravel-pack portion of the perforate and pack application.

Squeeze Position Figure 12.8 — The washdown system has a washdown shoe added to the bottom of the toolstring, allowing the wellbore to be washed free of fines and debris before a gravel-pack or FracPac treatment is performed. 132

The squeeze position of the multiposition service tool allows the gravel-pack media to be pumped downhole into fractures, perforations, and the annular pack area. Tool functions are actuated by a setting dart that is dropped

Circulating Position/Perforating

Perforating

Squeeze Position

Lower Circulating Position

Pack Completed Formation Isolated

Tubing Multiposition Tool Gravel-Pack Packer

Flapper Valve (Open)

Flapper Valve (Closed) Production Screen O-Ring Sub

Telltale Screen

GO Packer

Gun-Release Sub

Perforating Guns

Figure 12.9 — The Perforate and Pack configuration can be run for FracPac applications or gravel packs. Since perforating and packing are accomplished in a single trip, rig-time savings can be substantial.

133


Absolute Isolation System (AIS)

down the tubing string at the beginning of the squeeze stage. The setting dart first allows the packer to be set and tested against the pressure applied to the annulus. Then, by using rig pull and pressuring the tubing, the dart is forced farther down the tool where it will seat and block the gravel-pack ports. Pressuring the tubing string again opens the gravel-pack ports and rig weight is applied to lower the service tool into squeeze position. The setting dart now functions as a plug for gravel packing and as a ball check valve to prevent fluid loss when the tool is in the circulating and lower circulating positions.

Multiposition Tool Gravel-Pack Packer

Lower Circulating Position Rig pull is applied to the downhole assembly to move the multiposition tool from the squeeze position to the circulating position. Returns are collected at the screen and flow up the washpipe.

Pack Completed When the gravel-pack portion of the perforate and pack application is completed, the service tool is retrieved from the well. As the washpipe is pulled uphole it releases a prop from the flapper, allowing the flapper to seat. The formation is now isolated from the wellbore fluids.

Absolute Isolation System

Production Screen Washpipe

Telltale Screen

The Absolute Isolation System (AIS) is a downhole tool system that allows the FracPac or gravel-packed interval to be isolated from the annulus fluids before retrieving the multiposition service tool from the wellbore. Refer to Figure 12.10 for a schematic of the Absolute Isolation System. During the packing procedure, the washpipe functions as a return string. After the packing portion of the service, the washpipe forms an inner isolation string to protect against fluid loss to a lower-pressured formation and fluid flow from a higher-pressured formation. If fluid control is not a problem, the washpipe can be removed with the service string after the gravel pack is placed.

Sump Packer

Horizontal Systems

Figure 12.10 — The Absolute Isolation System allows FracPac- or gravel-pack-treated intervals to be isolated from annular wellbore fluids before retrieving the multiposition service tool from the hole. The washpipe functions as an inner isolation string after the packing portion of the service has been performed.

134

FracPac Completion Services offers fracturing and sand control for horizontal well applications in both the cased and openhole sections of the well. Refer to Figure 12.11 for a schematic of horizontal systems. Such horizontal applications present unique problems in deploying, setting, and retrieving sand-control equipment. Also, formation irregularities and the way they intersect the horizontal borehole present challenges to sand-control

Cased Hole Completion Lower Circulate Position

Cased Hole Completion Squeeze Position

Cased Hole Completion Upper Circulate Position

Openhole Completion with Inflatable Isolation Packers

Workstring

Production Seal Unit Upper Ports Gravel-Pack Packer Lower Ports Ported Flow Sub (Closing Sleeve Optional) Horizontal Ball Seat Positive Indicator (Optional) Shear Joint

Inflatable Packer

Wash Pipe

Production Screen

Inflatable Packer

Telltale Screen Sump Packer Float Shoe Positive Indicator (Optional)

Figure 12.11 (shown vertical for clarity)— The FracPac string can be run into highly deviated and horizontal wells. Getting to depth, setting the tool, and retrieving the tool generally present problems in horizontal applications. Both cased and uncased intervals can be treated. Inflatable straddle packers isolate openhole intervals. 135


measures. Vertical fractures can lead to water coning and heterogeneous intervals can exert different pressures and producing capabilities, requiring special isolative completion techniques. Uncased sections of the wellbore can be isolated by running inflatable openhole packers. The packers are inflated with either wellbore fluid or cement. The use of the flapper shoe at the bottom of the string provides a circulating and reverse-circulating flow path for fluid within the workstring. This circulating fluid removes cuttings from the low side of the horizontal wellbore and helps push through openhole bridges. Other positions of the multiposition service tool actuate the circulating, reverse positions and set the retrievable and inflatable packers.

Single-Trip, Multi-Zone Gravel-Pack Systems (FracPac Optional) Multiple zones can be packed off and gravel packed with the single-trip, multi-zone system. A standard sump packer and retrievable gravel-pack packer are run as the bottom and top packers, respectively. To isolate the multiple zones between the sump and gravel-pack packer, inflatable isolation packers are deployed. The downhole equipment is positioned with the help of a sump packer that has already been set with wireline.The sump packer provides a positive connection with the collet on the lower end of the workstring that is being lowered. The collet engages with a positive snap to indicate the string has bottomed in the sump packer. The retrievable gravel-pack packer at the top of the string is the first component set after the desired depth is reached. Hydraulic force provided by the hydraulic setting tool extends the packer elements and slips to the casing wall. The lower isolation packer is now inflated by applying 2,000 psi of pump pressure down the workstring. After the packer is fully inflated, it is tested for pressure integrity. Fluid is injected into the formation. If the packer showed a leak, the leak would occur up the annulus. Returns at the surface would be seen only if all of the zones uphole from the lower packer were not taking fluid. Each successive isolation packer is tested against the open lower zones, unless all of the isolation packers are spaced at equal distances along the string. After all isolation packers are set and tested, pressure is applied down the annulus to actuate the setting dart. The setting dart opens the return flow path. The downhole zones are now ready to receive gravel-pack media. 136

The bottom zone is gravel packed first, followed by each of the zones as they progress uphole. Unless all of the gravelpack assemblies are spaced equally, the lower zone or zones will remain open while the zone of interest is being packed.

Slimhole System A number of products and tool components are now available to perform gravel packing through tubing. Although jointed tubulars are still used, the downhole tool system for slimhole applications is now commonly deployed on coiled tubing. The downhole tool system can be set on bottom, located in landing nipples, or located in the tubing string. These systems are generally applicable for short perforated intervals. The treatment is pumped, as mentioned previously, through either an existing tubing string, or a jointed or coiled tubing string that is run concentrically. Tool systems are available for 2-3/8-inch through 4-inch tubing sizes. Refer to Figure 12.12 for a schematic of available slimhole configurations.

Floater Gravel-Pack System Floater gravel-pack systems are designed to compensate for vessel heave in offshore gravel-pack applications. Floater system tool positions are actuated with rig weight down. The lower circulating, upper circulating, and reverse postions of the service tool and components allow for 6 ft of vessel heave upward and 6 ft downward. The tool systems may vary from single-zone FracPac or gravel-pack applications by lengthening the packer assembly for vessel heave and adding compression indicators for locating tool positions. Two types of position indicators are available for use with floater systems. One provides consistent, snap-through indication, and the other uses compressive loading for position indication. Figure 12.13 shows a floater gravel-pack system. The gravel-pack assembly was extended a total of 24 ft to compensate for vessel heave.

COMPLETIONS FOR MODERATESANDING-TENDENCY FORMATIONS (OPTIPAC) Formations with high permeability and moderate sanding tendency can be kept from sanding by alternative methods to gravel pack with its screen and large annulus packs. The FracPac completion service for this type of application is OptiPac. OptiPac consists of a tip-screenout fracturing procedure in which a final stage of resin-coated proppant is pumped.

Fluted Hanger

Dual Screen Methods

Locator Hanger

Concentric Screen

GO Packer

Overshot

Fluted Hanger

Locator Assembly

Wireline Fishing Neck

Bow Spring Centralizers

Figure 12.12 — Slimhole FracPac and gravel-pack systems provide fracturing and packing capability through some sizes of existing production tubing. Performing these services on coiled tubing is becoming more and more popular. Tool systems are available to run concentrically in tubing sizes from 2-3/8-inches to 4-inches.

137


Floater System Lower Circulate

Upper Circulate

Squeeze Position

Reversing Out

Multiposition Service Tool

Gravel-Pack Packer Flow Sub

Production Screen

O-Ring Sub Telltale Screen

Sump Packer

Figure 12.13 — FracPac and gravel-pack services can be run in offshore conditions that require extreme positioning flexibility for drilling vessel heave. These tool systems provide longer packer assemblies to protect against workstring movement while allowing as much as 6 ft of vessel heave upward and 6 ft downward.

138

Resin-coated proppants are supplied in several different forms: precured, partially cured, curable, and coated onthe-fly. These coated proppants are used for OptiPac applications to form a permeable, stable proppant pack at the wellbore that restricts proppant flowback and formation sand flow. The proppant grains bond at their points of contact when pressure is applied by closure stresses in the fracture, forming a consolidated yet conductive proppant pack without flow-restrictive hardware such as screens and a full-annulus gravel pack. Refer to Proppant and Proppant Selection in Chapter 10 of this publication for a more thorough discussion of resin-coated proppants and their application.

Workstring Components and Considerations OptiPac procedures are performed much the same as any fracture stimulation. The workstring consists of a retrievable packer run to setting depth in the wellbore on a tubing string. The packer is set, and the fracturing fluids and proppants are pumped through the tubing. Generally, the annulus between the tubing and casing is pressured so that any leakage across the packer can be detected at the wellhead. Several variations of packers and other isolation hardware are used to pack off perforated zones from other production zones or the remainder of the casing volume.

Retrievable Packers Retrievable packers are run and set on the end of the workstring to isolate the perforated zone to be fractured from the balance of the casing volume. Retrievable tools, as a general rule, must be removed from the wellbore before the well is put on production.

Integral-Bypass Packer One type of packer that is used in OptiPac applications is an integral bypass, full-opening packer suited for fracturing, acidizing, testing, and squeezing. Packers usually consist of a packer-body assembly, a circulating-valve assembly, and sometimes a safety joint. The packer body includes a J-slot mechanism, mechanical slips, elastomeric sealing elements, and hydraulic slips. Drag springs or blocks on the lower body resist rotation when rig torque is applied to set or retract the packer.

Other features that make the integral bypass retrievable packer attractive for OptiPac service are • The full-opening mandrel permits large volumes of fluid to be pumped through the packer and perforating guns and wireline tools to easily pass through for operations in the packed-off interval. • Since the packer sets and retracts, it can be used for multiple operations in a single trip into the well. • Large, heavy-duty slips are set with hydraulic force generated below the packer to reinforce the elastomeric seals of the packer and prevent differential pressure from pushing it uphole. • Even though the packers are retrievable, they have very high differential pressure ratings. • The full-opening, retrievable packers cover a wider range of pipe and casing sizes than most retrievable packers. This wider range of sizes is useful in strings that have mixed weights of casing and pipe installed. • The integral bypass helps wellbore fluids pass around the large diameter packers when the tool is being run into the well. Also, the bypass provides a means of equalizing the pressure on both sides of the packer and in some operations can be used to spot fluids above the packer.

Concentric-Bypass Packer Another alternative retrievable packer is the concentricbypass device. Such packers are designed for use in deviated and horizontal wells since less reciprocating force and torque is required to set and retract the packer. The concentric bypass design of the packer ensures a fluid path around the slips when cleanup from a squeeze job such as OptiFrac is performed. Other features that make the concentric bypass, retrievable packer attractive for OptiPac service are • This type of packer can handle high-rate, high-volume treatments that contain high sand concentrations. • Straight, upward pull on the workstring opens the bypass and retracts the packer easily, especially in deviated and horizontal wells where torque and reciprocating rig force are lost due to bends in the workstring. For full size ranges and specifications of retrievable packers used in OptiFrac treatments refer to Table 12.4A through Table 12.7A in the appendix at the end of this chapter.

139


Retrievable Bridge Plugs Retrievable bridge plugs are used to isolate lower sections of casing from squeezing, treating, or testing operations being performed on an interval above. The lower sections of the well that are being protected may be perforated intervals, openhole sections, or uncemented casing. Halliburton recommends that a packer-type, retrievable bridge plug be used in OptiPac applications. The packer can be run alone on tubing or below one of the retrievable packers previously mentioned. Bridge plugs are run into the hole, set, and then released from the tubing or from below the packer. They are left in place until the tubing or retrievable packer is reattached. The bypass valve is then opened, and the slips are released to trip the workstring out. Sand is spotted on top of the bridge plug to prevent other debris from settling around the retrieving neck during operations in the packed-off zone. The bridge plug can be moved and reset at another depth in the well or removed from the well after the treatment is complete. The packer-type bridge plug recommended for OptiPac service has other advantages such as • The packer-type sealing elements are less susceptible to damage than cup-type elements used on other bridge plugs. This is because the sealing elements are not in direct contact with casing while tripping into the well. • Once set, this bridge plug does not move up and down in the casing, regardless of pressure reversal across the plug. • Packer-type bridge plugs are preferred in heavily perforated casing since they are not in direct contact with casing in transit and conform to irregularities in the casing wall much easier than cup-type bridge plugs. • Packer-type sealing elements are advantageous in heavy well-fluid systems and in wells that require the packer to enter a liner top on the way to setting depth. Retrievable bridge plugs are available in a full range of sizes and pressure ratings for use in OptiPac service.

140

COMPLETIONS FOR NO-SANDINGTENDENCY WELLS (OPTIFRAC) Formations with high permeability and no sanding tendency generally need stimulation techniques performed that bypass near-wellbore damage. The FracPac completion service prescribed for this type of well is OptiFrac. OptiFrac is a tip-screenout fracturing procedure that creates wide, short fractures to bypass permeability damage in the nearwellbore region. This permeability damage can be caused by invasion of drilling fluids, invasion of completion fluids, and instability in the perforation tunnels. Techniques such as oriented perforating and components such as resin-coated proppants are used in the OptiFrac service to enhance fracture propagation and conductivity. Refer to Proppants and Proppant Selection (Chapter 10), for more detailed information about resin-coated proppants. OptiFrac jobs are pumped by lowering an open-ended packer into the well on the tubing string. No mechanical gravel-pack equipment is placed in the well. Refer to Job Procedures and Best Practices, (Chapter 14), for more detailed information on job sequence for OptiFrac applications.

REFERENCES 1. Saucier, R.J.: “Gravel-Pack Design Considerations,” Paper 4030, 47th Annual SPE and AIME Fall Meeting (1972) 16.

APPENDIX This appendix contains size ranges and specifications in tabular form for the components discussed previously in the main body of the chapter. Table 12.1A — Multiposition Tool Sizes and Flow Rates MPT Tool Size (in.)

Maximum Flow Rate (bbl/min)

2.55 and 2.75

8

2.55 and 2.75 HIGH-RATE

15

3.25

16

3.88

23

5.00 standard

23

5.00 special

36

Table 12.2A — Versa-Trieve Packers Casing Size

Casing Weight

Packer OD

Packer Bore ID

Production Seal Assembly ID

(in.)

(mm)

(lb/ft)

(in.)

(mm)

(in.)

(mm)

(in.)

(mm)

4.500

114,30

9.5 - 11.6

3.82

97,30

2.380

60,45

1.735

44,07

5.000

127,00

15 - 18

4.09

103,89

2.55

64,77

1.927

48,95

23.2 - 24.1

3.82

97,03

2.380

60,45

1.735

44,07

14 - 17

4.67

118,62

22.750

69,85

1.927

48,95

20 - 23

4.50

114,30

20 - 24

5.73

145,54

5.000 6.625

139,70 168,28

17 - 23

7.000

7.625

177,80

193,68

9.625

196,85

59,69

2.350

59,69

3.880

89,55

3.050

77,47

82,55

2.350

59,69

98,55

3.050

77,47

145,54

3.250

82,55

2.350

59,69

5.82

147,83

3.880

98,55

3.050

77,47

6.68

169,67

3.250

82,55

2.350

59,69

3.880

98,55

3.050

77,47

3.250

82,55

2.350

59,69

3.880

98,55

3.050

77,47

3.250

82,55

2.350

59,69

3.880

98,55

3.050

77,47

3.250

82,55

2.350

59,69

3.880

98,55

3.050

77,47

3.880

98,55

2.350

59,69

5.000

127,00

3.850

97,79

3.880

98,55

2.350

59,69

5.000

127,00

3.850

97,79

32 - 38

5.73

32 - 35 24 - 29.7

46.1 - 48.6

2.350

82,55

3.250

6.00

29.7 - 39

156,72

82,55

3.880

23 - 29

39 - 47.1

7.750

6.17

3.250 3.250

6.44

6.17

6.17

36 - 43.5

8.52

43.5 - 53.5

8.30

152,40

163,58

156,72

156,72

216,41

244,48 210,82

141


Table 12.3A — Perma-Series® Production Packers Casing Size (in.)

(mm)

4.500 114,30

5.000 127,00

5.500 139,70

Casing Weight

7.000

7.625

9.625

168,28

177,80

193,68

244,48

Optional Seal Unit ID*

(lb/ft)

(in.)

(mm)

(in.)

(mm)

(in.)

(mm)

(in.)

(mm)

(in.)

(mm)

(in.)

(mm)

3.790

96,27

2.555

64,90

1.677

42,60

1.810

45,97

1.910

48,51

1.920

48,77

9.5 - 13.5

3.720

94,49

2.375

60,33

1.530

38,86

1.735

44,07

13.5 - 15.1

3.600

91,44

2.375

60,33

1.530

38,86

1.735

44,07

13.5 - 15.1

3.640

92,46

2.555

64,90

1.677

42,60

1.810

45,97

1.910

48,51

1.920

48,77

15 - 21

3.960 100,58

2.555

64,90

1.677

42.60

1.810

45,97

1.910

48,51

1.920

48,77

1.920

48,77

**15 - 21

3.960 100,58

3.120

79,25

2.390

60,71

23.2 - 24.2

3.790

96,27

2.555

64,90

1.677

42.60

1.810

45,97

1.910

48,51

13 - 20

4.540

115,32

2.750

69,85

1.830

46,48

1.920

48,77

1.927

48,95

13 - 20

4.540

115,32

3.000

76,20

1.927

48,95

2.240

56,90

2.330

59,18

20 - 26

4.360

110,74

2.750

69,85

1.830

46,48

1.920

48,77

1.927

48,95

20 - 26

4.360

110,74

3.000

76,20

1.927

48,95

2.240

56,90

2.330

59,18

4.360

110,74

63,75 1.920

48,77

1.927

48,95

3.500

88.90

2.510

17 - 32

55,468 138,39 2.750

69,85

1.830

46,48

17 - 32

55,468 138,39

3.250

82,55

2.350

59,69

20 - 24

5.687

144,45

4.000

101,60

2.970

75,44

17 - 20

6.250

158,75 4.000

101,60 2.970

75,44

1.920

48,77

1.927

48,95

17 - 23

6.180

156,97

3.250

82,55

2.350

59,69

1.920

48,77

1.927

48,95

20 - 26

6.000

152,40

4.000

101,60

2.970

75,44

23 - 38

5.687

144,45 2.750

69,85

1.830

46,48

23 - 38

5.687 144,45

3,250

82,55

2.350

59,69

**23 - 38

5.687

144,45

4.250

107,95

3.250

82,55

26 - 32

5.875

149,23 4.000

101,60 2.970

**26 - 32

5.875

149,23

5.000

127,00

3.938

100,03

32 - 38

5.687

144,45

4.000

101,60

2.970

75,44

32 - 44

5.468

138,89 2.750

69,85

1.830

46,48

43 - 44

5.468

138,89

3.250

82,55

2.350

59,69

26.4 - 33.7

6.375

161,93

2.750

69,85

1.830

46,48

1,920

48,77

1.927

48,95

26.4 - 33.7

6.375

161,93 3.250

82,55

2.350

59,69

26.4 - 33.7

6.375

161,93

4.000

101,60

2.970

75,44

33.7 - 39

6.180

156,97

3.250

82,55

2.350

59,69

33.7 - 39

6.250

158,75 4.000

101,60 2.970

36 - 47

8.420

213,87

6.000

152,40

4.400

111,76

4.860

123,44

36 - 59.4

8.120

206,25

3.250

82,55

2.350

59,69

111,76 4.860

123,44

75,44

75,44

36 - 59.4

8.120

206,25 4.000

101,60 2.970

75,44

36 - 59.4

8.120

206,25

5.000

127,00

3.850

97,79

**36 - 59.4

8.120

206,25

6.500

165,10

5.000

127,00

40 - 53.5

8.220

208,79 6.000

* thread type and size control Seal Unit ID ** Available in RATCH-LATCH® Style Only

142

Seal bore ID

9.5 - 12.6

**20 - 26 6.625

Packer OD

152,40 4.400

Table 12.4A — RTTS Packers Casing OD (in.)

Casing Wt (lb/ft)

Nominal Tool OD ( in.)

Min. ID (in.)

Casing OD (in.)

Casing Wt (lb/ft)

Nominal Tool OD ( in.)

Min. ID (in.)

2 3/8

4.6

1.81

.60

6 5/8

24 - 32

5.43

1.90

2 7/8

6.4

2.22

.75

6 5/8

17 - 20

5.65

2.40

2 7/8

7.9 - 8.7

2.10

.60

7

32.38

5.65

2.40

3 1/2

5.7

2.93

.62

7

49.5

5.25

2.00

3 1/2

9.2 - 10.2

2.70

.62

7 5/8

20 - 39

6.35

2.40

3 1/2

13.3

2.50

.62

8 5/8

24 - 49

7.31

3.00

4

9.5 - 11.6

3.18

1.12

9 5/8

29.3 - 53.5

8.15

3.75

4

12.5 - 15.7

3.06

.865

9 5/8

40 - 71.8

7.80

3.00

4 1/2

9.5

3.79

1.80

10 3/4

32.75 - 51

9.30

3.75

4 1/2

15.1 - 18.1

3.55

1.51

10 3/4

55.5 - 81

8.85

3.75

4 1/2

11.6 - 13.5

3.75

1.80

11 3/4

38 - 54

10.20

3.75

5

21

3.75

1.80

11 3/4

60 - 71

10.10

3.75

5

23

3.75

1.80

13 3/8

48 - 72

11.94

3.75

5

15 - 18

4.06

1.80

13 3/8

72 - 98

11.50

3.75

5

11.5 - 13

4.25

1.80

16

109 - 146

13.62

3.75

5 1/2

23 - 26

4.25

1.90

16

65 - 109

14.18

3.75

5 1/2

20 - 23

4.38

1.80

18 5/8

78 - 118

16.87

3.75

5 1/2

13 - 20

4.55

1.80

20

94 - 133

17.87

3.75

6

15 - 23

5.06

1.90

20

169 - 204

17.25

3.75

Table 12.5A — Maximum Pressure Differentials for RTTS Packers Maximum Pressure Differential (psi) at Temperature

Casing Size, OD, in.

180°F

250°F

325°F

400°F

2 3/8 - 5 1/2

10,000

10,000

10,000

10,000

6 5/8 - 7 5/8

10,000

10,000

10,000

10,000

8 5/8 - 9 5/8

10,000

10,000

8,000

7,000

10 3/4 - 13 3/8

7,500

5,000

3,000

no data

16 - 20

5,00

5,000

3,000

no data

143


Table 12.6A — CHAMP Packers Casing Size, OD (in.)

Casing Wt. Range, (lb/ft)

4 1/2

9.5 - 10.5

5

23

4 1/2

Nominal Tool OD, (in.)

Min. Tool ID, (in.)

3.98

1.80

11.6

3.84

13.5

3.75

5

11.5 - 15

5 1/2

26

1.80

4.18

1.80

5

18 - 21

3.98

1.80

5 1/2

13 - 20

4.57

2.00

5 1/2

20 - 23

4.40

1.80

6 5/8

28 -32

7

41 - 49.5

5.25

2.00

7

17 - 38

5.65

2.37

7 5/8

20 - 39

6.35

2.37

9 5/8

29.3 - 43.5

8.15

2.87

9 5/8

40 - 71.8

7.80

2.87

10 3/4

55.5 - 81

8.85

3.00

11 3/4

38 - 71

10.10

3.00

13 3/8

48 - 72

11.94

3.75

13 3/8

72 - 98

11.50

3.75

7

17 - 38

5.65

2.37

7 5/8

20 - 39

6.35

2.37

9 5/8

29.3 - 53.5

8.15

2.87

9 5/8

40 - 71

7.80

2.87

Table 12.7A — Maximum Pressure Differentials for CHAMP® Packers Casing Size, OD, in.

144

Maximum Pressure Differential (psi) at Temperature

180°F

250°F

325°F

400°F

4 1/2 - 5 1/2

8,400

8,400

8,400

8,400

7 - 7 5/8

10,000

10,000

10,000

10,000

9 5/8

10,000

10,000

8,000

7,000

13 3/8

7,500

5,000

3,000

no data

Chapter 13 INTRODUCTION FracPac operations use extensive amounts of surface equipment that must be transported to the jobsite and prepared for operation. The amount and type of equipment that is selected to perform the job is determined by considering the well location, site accessibility, rig floor space, weight restrictions, and general downhole conditions of the well to be treated. Equipment used to perform FracPac Completion Services can generally be divided into functional categories such as fluid-preparation systems, pumping equipment, proppant storage and delivery systems, data acquisition and analysis hardware, and fracture design and analysis software. Halliburton offers a complete selection of equipment necessary to meet all the specific job requirements of FracPac Completion Services.

FLUID PREPARATION SYSTEMS Proper preparation of the fracturing-fluid systems is critical to the effectiveness of FracPac techniques and is one of the most equipment-intensive operations performed at the wellsite. Special filtration systems and blending and mixing equipment must be delivered, setup, and checked for proper operation before preparing any fluids or additives.

Filtration Equipment Fluid filtration is recommended before any gravel-pack treatment is performed. Any solids or microgels that may be present in the fluid system must be

removed. If these substances are not removed from the gel fluid system, formation permeability could be damaged in the near-wellbore region, which, in turn reduces well productivity.

Surface Equipment

For many FracPac operations, filtration of fluids has not been given high priority, since the fracturing and packing techniques resulted in larger exposed areas of the formation face and thus less drawdown at the wellbore. Some damage at the fracture face and to the proppant pack was expected and could be tolerated. A certain amount of tolerated formation damage was caused by the inordinate amount of time needed to filter large volumes of gelled fluids. It is, however, recommended that the brine used as source water be filtered before mixing with gel polymer. Also, all fluids used for gravel packing and well completion should be filtered to minimize any damage to the immediate-wellbore region. For most gelled fluids, a two-pod, cartridge-type filter unit provides an economical solution for filtering unwanted solids as small as 10 microns. Fluids that are not yet gelled should be processed through a 2-micron filter if possible. The body of the filtration unit should be constructed of stainless steel to minimize the introduction of corrosion products to the fluid systems. Diatomaceous earth filter systems and systems designed to handle high pressure are available for special requirements. The cost associated with using diatomaceous and high-pressure filter systems usually restricts them to use in large volumes of ungelled brines.

145


Data Acquisition Job Monitoring Digital Densometer Flow Meter

W

Dry Sand Addition

ell Returns

Fluid Source

Halliburton 6x5 Centrifugal Pump

To Work String

Hi gh Pr es su re Di sc ha rge

Recirculating Loop

Pressure

proppant settling in the tanks, mechanical agitators with four stainless-steel mixing blades cycle continuously while proppant is present. These agitators are also hydraulically driven, which allows variable speed control. Variable speed control allows the agitator to turn slow enough to avoid air entrainment in the fluids being mixed. Optional configurations of this batch-mixing system are available for smaller operations, one with two 20-bbl stainless-steel tanks and the other with two 15-bbl crosslinkedpolypropylene tanks. Recommended mixing procedures for batch-mixing equipment are to mix the proppant at high concentrations, typically 12 to 16 lb/gal, and dilute the mixture with clean gel while pumping. This dilution process helps obtain the required downhole proppant concentration.

HT-400 Pump Unit

Constant-Level Additive Mixer (CLAMTM) CLAMTM

Figure 13.1 — The blender processes a constant level of even low-concentration proppants such as those that are pumped in early stages of a FracPac treatment. This blender is very accurate and economical.

MIXING AND BLENDING EQUIPMENT Mixing and blending equipment for FracPac Completion Services is available in a variety of types and sizes. Each size and type of system is designed to perform in different conditions and applications. Batch-mixing systems are available for smaller operations. Constant-level additive mixers provide the capability for jobs with low pumping rates or low proppant concentration. Continuous blending systems provide complete mixing and delivery systems that handle proppants, liquid additives, and dry additives.

Batch-Mixing Systems Batch-mixing systems can be configured many different ways. For smaller operations, a standard skid-mounted unit can provide very economical mixing capability. Larger jobs can be performed with additional units added to the system, but space and weight requirements soon govern and may preclude the use of this type of system. The standard batch-mixing system is configured with two 25-bbl stainless-steel mixing tanks, and two hydraulically driven centrifugal pumps. Hydraulic drive on the pumps allows speed control from 0 to 1,500 rev/min. To prevent

146

The constant-level additive mixer is an ideal choice for FracPac jobs in which low rates or low proppant concentrations must be pumped. Refer to Figure 13.1 for a schematic of this blender system. Low pumping rates, from 3 to 10 bbl/min, can be pumped with this mixer, which restricts its use in some fracturing applications but makes it very economical for others. The constant-level additive mixer can be used to mix the lowerconcentration proppants that are pumped earlier in the job, and a batch mixer can be used to mix the higherconcentration, tail-in proppants pumped at the end of the job. This technique works well for FracPac and gravel-pack treatments with small total volumes.

Continuous Blending Equipment Halliburton has a wide range of fracturing blenders available for use in FracPac Completion Services, fracturing services, and gravel-pack services. Units capable of handling pumping rates from 3 to 100 bbl/min and proppant concentrations of 1 to 18 lb/gal are currently in use. Most of the continuous blending systems have been trailer-mounted for land operations and skid-mounted for offshore operations. With increasing demand for fracturing operations in high-permeability formations and the development of FracPac Completion Services, Halliburton has designed and built a continuous blending system specifically for offshore services of this nature. This new blending system will meet the following specifications:

• The blender meets ISO package specifications with DNV capability (8 ft wide x 8.5 ft high x 20 ft long). • Weight distribution complies with 500 lb/ft2 supplyvessel deck load limit. • Configuration allows vessel offshore platform operation. • Power package is self-contained. • Power unit is air started, diesel powered, and radiator cooled. • Liquid additives, dry additives, and tub agitation are hydraulically powered. • Remote control is completely automatic, with manualoverride backup system for offshore operations. • Electrical systems are corrosion-proof. • Suction and discharge pumps have individual, hydraulically driven speed controls. • Flow rates from 4 to 40 bbl/min at proppant concentrations of 0.5 to 18 lb/gal • Proppant delivery is a maximum of 240 sacks/min. • Additive pumps are automatically controlled and as many as five pumps can be in the system. • Additive pumps are available to cover a wide range of rates and job requirements. • Dry additive systems are automatically controlled and as many as three can be used in the system. • Dry additive systems can be selected for low-concentration additives such as breakers or high-concentration additives for fluid-loss control. • The blender uses a vertical, cylindrical tub of 4-bbl capacity with discharge pump mounted immediately beneath the tub to minimize air-entrainment problems in high-viscosity gel systems. • The blender weight conforms to worldwide lifting limits of 10 tons, and it can be compartmentalized. • The blending system was specifically designed for FracPac Completion Services and should simplify the choice of equipment for such services.

HIGH-PRESSURE PUMPING EQUIPMENT Most FracPac Completion Services operations call for the highest injection rate and the highest proppant concentration possible for the specific well conditions. Job histories have recorded most FracPac injection rates at 12 to 25 bbl/min. With injection rates such as these and with stringent space and weight limitations, high-horsepower pumping units are recommended for FracPac operations. All equipment designed for FracPac applications can withstand the sustained high injection rates and high proppant concentrations encountered. For land operations, the nearest available standard fracturing unit can be used to perform FracPac jobs. In offshore applications, skid-mounted units are usually the pumping equipment of choice if a dedicated stimulation vessel cannot be obtained. Halliburton offers a wide array of pumps for fracturing operations. Selection of the pumping equipment that is best suited to the job depends on the anticipated pumping pressures, injection rate, total pumping time, and economics. Most FracPac operations involve pumping durations that are very short and an injection pressure between 2,000 and 7,000 psi. The pump recommended for FracPac applications, such as the one mentioned in the previous paragraph, is one that has performed faithfully in stimulation and cementing services since 1957. This horizontal triplex pump (HT-400) began with a 400-horsepower rating and has since been constantly improved to yield an 800-horsepower rating that sets the standard in the oilfield industry. The HT-400 has been the preferred pump for well control and relief-well pumping for major blowouts and emergencies. The mechanical integrity of these pumps makes them first choice for FracPac applications, since there is no margin for error while pumping small volume treatments. With total pumping time at only 10 to 30 minutes and the requirements of the tip-screenout technique, pumping equipment must be failure-free. Since fluid efficiencies are usually very low with FracPac applications any shutdown caused by equipment failure would most likely end the treatment. Either redundant equipment should be on site, which is costly, or the primary pumping equipment must be reliable. If higher pump rates or limited space for placement is a requirement, the quintaplex pump (HQ) is recommended, since it can achieve up to 2,000 hhp. Operating systems for pumping equipment range from pneumatic control to microprocessor-driven, automatic remote control. Job requirements and equipment availability govern the selection of pump operating systems. 147


Discharge Hoses Special high-pressure hoses are used to transmit fluids from the pumps to the wellhead. Offshore operations require that a flexible, high-pressure hose be used for vessel-toplatform pumping. A hydraulic disconnect is also mandatory to allow the stimulation vessel to disengage from the rig or platform in an emergency. Backpressure valves isolate the wellhead pressure if the vessel needs to disengage.

Crew's Quarters and Wheelhouse

Observation Deck and Control Room Downhole Pump Suction and Discharge Manifolding

Downhole Pumps High Pressure Downhole Pumps High Pressure Downhole Pumps High Pressure Downhole Pumps High Pressure Downhole Pumps High Pressure

Platform Rig Up Blender bypass

3 1/2 in. IF Tubing with full-opening TIW valve

Downhole Pumps High Pressure

Rig manifold to casing


Electronic Pressure Transducers

Proportioning Blender High-Pressure Regulating Pop-Off Valve

Flow Meter Radioactive Densometer

High-Pressure Discharge Line to annulus

Halliburton Lo Torc Valve

Check Valve

High-Pressure Discharge Line to tubing


Rig Pump

Gel feed line from below deck storage

Sand Tank

gel feed line from below deck storage

High-Pressure Regulating Pop-Off Valve

Offshore Stimulation Vessel

High-Pressure Discharge Line from Offshore Vessel

Hydraulic Quick Disconnect

Pumping rates determine discharge line size. For rates of 10 bbl/min and higher, a 3-inch Coflexip hose is recommended. For pumping rates below 10 bbl/min, a 2-inch Coflexip hose is recommended.

PROPPANT STORAGE AND DELIVERY Proppant supply to the blender during fracturing operations is critical. A storage and delivery system is necessary to maintain a constant flow of proppant to the blender. Bulk delivery of proppant to the wellsite for land-based FracPac jobs is performed with covered dump trucks. Proppant transport from the dump trucks to the blender is then continued by pneumatic systems or conveyor belts. Offshore proppant storage and delivery, however, presents other challenges. Space, weight, and height limitations must be considered when planning offshore operations. On fixed platforms, height of stored proppant is not as critical a concern as it is on stimulation vessels where the center of gravity must be kept low. Storage of proppant on platforms is usually in vertical silos with flow-control gates. Maximum size of these silos is location dependent, but typical silos hold 300 ft3 to 700 ft3. In stimulation vessels, proppant can be stored in several bins and connected by a common conveyor system to the blender. Long-term location of such bins and conveyor systems should be on the lower deck of the stimulation vessel, whereby the center of gravity is lowered. Figure 13.2 shows a schematic of offshore-vessel and platform equipment placement.

High-Pressure Discharge Line to Platform

Figure 13.2 — The layout of the stimulation equipment on vessels and platforms for offshore FracPac and gravel-pack treatments is critical. On vessels especially, horizontal and vertical weight distribution affects the center of gravity. Equipment placement on platforms is crucial for personnel safety and efficient working conditions.

148

Most Halliburton blender systems use automatically controlled and calibrated sand screws that regulate the flow of proppant to the blender tub. This system has gained worldwide acceptance through many years of use in fracturing operations. Alternate delivery systems, however, are being considered for offshore operations where space and weight must be minimized. Such delivery systems use automatically controlled, calibrated gates to regulate proppant flow rates by changing the flow area of the gate. Effectiveness of the proppant delivery systems can be

measured by a radioactive densometer located in the discharge line. This densometer allows adjustments to be made to the proppant flow during fracturing operations.

DATA ACQUISITION AND ANALYSIS SYSTEMS When performing fracturing treatments, the surface treating pressures of the workstring and annulus, the downhole pumping rate, and the proppant concentration should be monitored and recorded. Data acquisition systems perform the monitoring and recording functions. Halliburton uses one of three data acquisition systems, depending upon what is needed for the particular job. Two of the three systems are PC-based, and the third runs on a minicomputer.

Portable Surface Data System The portable surface data system is a PC-based, portable data acquisition system mounted in a ruggedized case. The data acquisition system provides the following: • Inputs are available for three pressures, three flow rates, one density, and one temperature. • A local-area network (LAN) connection that allows simultaneous data acquisition from UNIPRO data acquisition systems is mounted locally on the equipment. • An overhead display is provided for numerical data acquired during treatment. A strip chart plot of critical job parameters is made in real time during the treatment. • Standard ASCII format, IBM-compatible data can be output to 3-1/2-inch diskettes for transport and detailed posttreatment analysis. For treatments where surface data monitoring is sufficient, the COMPUPAC system provides very reliable, economical data acquisition. This system can be complemented with a display on the rig floor at wellsites where access to the stimulation vessel is limited. Company personnel can then monitor the job at the rig.

Surface and Bottomhole Data System The surface and bottomhole data acquisition system is also a PC-based system. This system has been expanded to allow up to two additional monitors for the display of real-

time surface data and calculated bottomhole data in either numerical or graphical format. Acquisition capabilities are identical to the surface data system, but the capability to calculate bottomhole treatment pressure allows real-time decisions and adjustments to be made during the treatment. With a simple modification, the surface and bottomhole data system can transfer data to a second PC where input is made to software such as FRACPRO, to model and evaluate the treatment in real-time. The surface and bottomhole data system requires a larger, sheltered area for setup and operation.

Technical Command Center The Technical Command Center is a minicomputer-based acquisition and control system. This system provides data acquisition, real-time data analysis, and direct control of automatic, remote-control pumping and blending equipment. The Technical Command Center is one of the most advanced systems in the well-stimulation industry and offers the following features: • Monitors and records more than 1,200 surface treatment parameters including injection rates, additive rates, slurry density, pressures, material inventories, and equipment operating status. • Communicates with a wireline computer logging system via an RS-232 serial port to monitor bottomhole treating pressures and other parameters during the treatment. These data can then be used to analyze the treatment in real time. • Monitors real-time minifrac data to provide critical onsite fracturing parameters and, if necessary, data to redesign the fracture treatment. • Displays the log/log plot of the net bottomhole treatment pressure versus time, to make real-time adjustments to the fracturing treatment. • Transfers data to a PC if necessary, to interface with stimulation software such as FRACPRO. Technical Command Center fracture design software and FRACPRO can be used in combination to assist in real-time fracture analysis. • Transfers treatment data via satellite to the Halliburton Technology Center, allowing additional stimulation experts to use design/analysis software real time and make difficult decisions real time, if necessary.

149


FRACTURE DESIGN AND ANALYSIS SOFTWARE Many forms of software for fracture design and analysis are available. Traditionally, Halliburton has developed its own advanced fracture-design software; however, advances in PC technology have made other software resources available for reliable fracture design. So many programs exist for fracture design that it is not within the scope of this publication to discuss them all. Two programs have been tested and proven reliable for FracPac Completion Services. These programs are FRACPAC and FRACPRO. A third program, STIMPLAN, has also been used for fracture design of high-permeability formations. Although these programs are part of the equipment at the jobsite, their complexity merits a separate discussion. These fracture design packages are discussed in detail in Fracture Design Simulators (Chapter 7).

RESERVOIR DESIGN SIMULATORS Although not part of the equipment that is transported and used at the jobsite, reservoir simulator and well-test design and production simulator software packages are very much a part of the equipment used to design and evaluate the effectiveness of FracPac Completion Services. The reservoir simulator used for FracPac Completion Services is RTZ, and the well-test design and production simulator is RESULTS.

• Partially penetrating wells • Radially composite reservoirs • Horizontal wells • Closed chamber tests • Single-well, vertical pulse tests • Combinations of the above RTZ can be configured with radially composite geometry to model a deep damage zone or a zone near the wellbore with impaired permeability caused by sand production. By running the simulator in constant-rate mode, the user can design a well test that will help characterize the permeabilityimpaired zone. Constant-pressure production can be simulated to generate a production-decline curve for the well with a permeability-impaired zone. Factors such as a vertical fracture or fracture-face damage can easily be incorporated into the radially composite model. A sensitivity study can be performed based on expected production to optimize the fracture design before the stimulation is performed. Also, RTZ can be run in constant-rate mode to design a well test that will evaluate a FracPac stimulation treatment. A more detailed discussion of the reservoir simulator and reservoir-engineering aspects of FracPac Completion Services can be found in Reservoir Engineering (Chapter 4) and Well Testing (Chapter 5).

RTZ Reservoir Simulator Halliburton uses the RTZ simulator to model threedimensional flow of single-phase oil, gas, or water within the wellbore environment. The simulator uses a cylindrical coordinate system. Either constant-rate mode can be chosen to simulate a well test, or constant-pressure mode can be chosen to yield a production decline curve. In addition to the simulator’s standard features, the model includes • Wellbore storage (may change with respect to time)

Halliburton also uses RESULTS, a well-test design and production simulator package that runs in a WindowsTM (a trademark of Microsoft Corporation) environment on a personal computer. This program allows the user to design well tests by inputting the well and reservoir characteristics, generating simulation data, and producing plots of the generated data.

The model can simulate

RESULTS has extensive pressure-behavior modeling capability. Simulations of drawdown-buildup tests, injection-falloff tests, drillstem tests, interference tests, and closed-chamber tests can be performed. Also, decline curves can be generated. The modeled reservoir parameters can be configured with

• Multilayered reservoirs

• Homogeneous or dual-porosity

• Hydraulic fractures with uniform or variable conductivity

• Vertical or horizontal well orientation

• Variable skin (different skin values for different formation layers may change with respect to time) • Turbulent flow

150

RESULTS Well-Test Design and Production Simulator

• Vertical wellbores can be fully penetrating, partially penetrating, or fractured. • Outer boundary can be infinite, circular, or composed of one or two nearby boundaries. • Boundaries can be a mixture of no-flow and constantpressure. • Composite reservoir or dual-permeability reservoir • Up to 10 layers with different reservoir and well conditions for each layer. One model available in RESULTS that is particularly applicable to FracPac Completion Services is the radially composite reservoir that contains a vertical fracture of finite conductivity. This model is a new analytical solution to a problem that was previously restricted to numerical simulator modeling. Analytical solution offers an advantage in speed over numerical solution when multiple sensitivity studies are performed. The RESULTS simulator can be run in constant-rate mode to design well tests for wells with near-wellbore damage or formation sanding problems. Parameters from the well test can be used to characterize the permeability-impaired zone and the unaltered reservoir. This information can then be input to the simulator (now running in constantpressure mode) to generate a production-decline curve. Performing sensitivity analyses on various fracture lengths and conductivities can help the stimulation treatment to yield maximum production within operational constraints and budget. After the well has been stimulated and allowed to produce, the RESULTS simulator can again be used to design a well test for a fracture of finite conductivity in a radially composite reservoir. The results of this type of well test can help evaluate the effectiveness of the FracPac treatment. Case Histories (Chapter 16) reviews some selected FracPac case histories that simulator predictions can use as reference points to prove and improve accuracy.

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Chapter 14

INTRODUCTION This chapter focuses on the wellsite tasks performed by Halliburton during a typical FracPac Completion Service or gravel-pack job. The effectiveness of the stimulation and sand-control job relies on the preparation and setup of equipment, and operational safety while operating that equipment. All aspects of the job, from rig-floor equipment, pumping equipment, downhole tools, fracturing and carrier fluids to proppants play a critical role in whether the stimulation is effective. The following categories contain concerns that may be used as a checklist.

SURFACE EQUIPMENT CONCERNS The Rig-Floor Equipment Layout The rig floor, whether on a land rig or an offshore rig, is the center of activity for operations on the well. Walkways must be left free of obstructions during the job for operating personnel to monitor job functions and make adjustments to equipment stationed on the rig floor. Great care should be taken not to jeopardize personal safety of anyone required to be on the rig floor. The following guidelines should be followed when setting up and operating the surface equipment on the rig floor. ____ Discharge lines should be located so that fluid path is optimum for injecting fluids down the workstring or down the annulus to reverse. ____ A high-pressure manifold should be connected to the sur-

face equipment to allow fluids to be pumped in any combination of paths by opening and closing the appropriate valves. ____ Full-opening valves should be mounted in any line through which high flow rates will be pumped. The full-opening valves impose minimum restriction to fluid flow.

Job Procedures and Best Practices

____ The return line from the manifold to the rig tanks should have an adjustable choke to regulate return rates while circulating or reversing the slurry flow. The discharge of this line should be visible so that it can be monitored for potential problems during the treatment. ____ Flow meters should be mounted in both the injection and return lines. ____ A densometer should be used to measure proppant concentration in both the injection and return lines. ____ Pressure transducers at the wellhead should be positioned so that both the workstring and the annulus can be monitored. ____ The workstring should have a minimum of two transducers active at all times. ____ All personnel with responsibilities on or near the rig floor should be within view of pressure readings, and preferably pump-rate and proppant-concentration readings, or be in direct radio contact with

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the treatment operator. This guideline enables rigfloor personnel to be aware of the job sequence. ____ The layout of lines and other equipment on the rig floor should be organized with minimum line length and line contact. An unobstructed path for foot traffic should be available to allow all personnel to access valves and perform other job functions. ____ All personnel not essential to pumping operations should stay clear of the injection and return lines on the rig floor during pumping.

____ If a crossover tool is used in the toolstring, it should be able to withstand the high flow rates associated with FracPac services. ____ Blank pipe used should be able to withstand screenout pressures. ____ The gravel-pack packer should be able to withstand high differential pressure when screenout occurs. ____ Potential tubing contraction should be calculated during the job. Tubing-string movement should be estimated and precautions should be taken to prevent such movement.

Equipment Equipment setup is essentially the same for FracPac service as it is for a conventional fracture stimulation. The following special concerns apply to FracPac jobs. ____ Proppant concentrations are unusually high compared to conventional fracturing jobs. Ensure that suction-hose lengths connected to high-pressure pumps are a minimum length.

Fracturing Fluids The effectiveness and efficiency of a FracPac stimulation relies on the quality of the fracturing fluids used to perform the procedure. Special care should be taken when handling and mixing fluids. The following concerns should be applied to protect fluid quality. ____ The cleanest base fluid possible should be used.

____ Sudden pressure increases can occur when performing tip-screenout fracturing. Premature screenout and/or fracture-entry restrictions are the primary causes for a sudden increase. All personnel should be aware of this possibility. ____ A high-rate pressure-release valve should be installed on the discharge line. The release line from the pressure-release valve should be strategically positioned and restrained so that personnel are not endangered should a pressure discharge occur. ____ For offshore operations, when pumping equipment is on a boat, a quick disconnect should be installed. The vessel can then release the discharge line and disconnect from the rig in an emergency. A backpressure valve should also be installed to prevent line discharge if an emergency disconnect is necessary.

____ Holding tanks should be inspected for cleanliness before adding base fluids. Substances such as rust, dirt, drilling mud, and old gel residue compromise fluid performance. ____ Each tank should be treated with biocide before the base fluid is added. ____ Pilot tests of the designed fracturing fluid should be conducted on location before preparing bulk quantities of fluid. Fluid properties such as viscosity, pH, break time, and crosslink time should be identified. Confirming tests should be performed after the fluid is prepared.

DOWNHOLE CONCERNS

____ Whenever possible, liquid gel concentrate (LGC) should be used to avoid lumping problems associated with unhydrated, powdered gel.

Downhole Tools

____ Shearing and filtering fluids should be considered in applications where ultraclean fluid is required.

Downhole tools must withstand higher pressures during a FracPac job than during a conventional fracture stimulation. The following concerns apply to downhole tools used to perform FracPac jobs and are checked by Halliburton.

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____ All base fluids should be filtered through a 10-micron filter or smaller.

Proppants ____ Proppants should be checked for proper type and size, and meet API specifications. Sieve analyses from each container should be used to establish size and fines content.

GENERAL JOB SEQUENCE The general job sequence progresses differently for FracPac applications where mechanical sand control equipment is placed in the wellbore than for applications where no sand control equipment is placed. The main differences between these two types of jobs is how the tools are positioned in the hole, and how the annular gravel pack is pumped after tip screenout has occurred in the fracture.

Jobs with Mechanical Gravel-Pack Equipment (FracPac) On jobs where gravel-pack equipment such as screens and blanks is to be set, the following sequence should generally be followed: 1. Retrieve perforating guns from the well after perforating. 2. Run the completion assembly into the hole. 3. When on depth, set the gravel-pack packer and reciprocate the workstring to set the multiposition tool in circulating position. Circulate completion fluid into the well to fill the annulus between casing and workstring with a fluid of known density. 4. Shut in the annulus and position the valve so that fluid can be pumped down the workstring while monitoring annulus pressure. 5. Pressure test all lines to 1,000 psi over the anticipated maximum job pressure.

9. Perform a minifrac test by pumping the proposed fracturing fluid at a constant rate. A step-down test can be performed as part of the minifrac test to determine whether any fracture-entry restrictions are present. 10. Displace the minifrac fluid and shut down the pumps immediately. Monitor the pressure decline until fracture closure is observed. 11. Calculate the fluid-leakoff coefficient, closure pressure, closure time, fluid efficiency, and friction pressure. Refer to Chapter 8 for the procedures involved in determining these coefficients and pressures. 12. Design a propped-fracture treatment that optimizes pumping rate, pad volume, and proppant schedule. 13. Perform the tip-screenout fracture treatment until screenout occurs or until the volume needed to form an annulus pack remains in the workstring. 14. Slow the pumping rate to 1-2 bbl/min and open the annulus valve through a choke. This choke allows the proppant pack to be dehydrated across the screen, forming an annular pack between the casing and screen. 15. Shut down the pumps when maximum pressure is achieved. Observe the pressure bleedoff. Restress the pack until a tight annulus pack is achieved. A “top off” gravel pack can be added, if necessary. 16. Reciprocate the workstring to select the reverse position on the multiposition tool. Reverse any excess slurry from the workstring. 17. Retrieve the workstring from the hole and run the production tubing and assembly into the well. 18. Clean up the well slowly to allow the gravel pack to stabilize.

6. Perform the step-rate test by pumping completion fluid, if possible. The step-rate test should pump a pressure high enough to exceed the formation fracture gradient. A friction-reducer additive may be necessary to reduce wellhead pressure while pumping higher rates. 7. Shut down the pumps and allow the pressure to return to near-initial reservoir pressure. 8. Evaluate the step-rate test to determine the fractureextension pressure.

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Jobs Without Mechanical Gravel-Pack Equipment (OptiPac and OptiFrac) On jobs where no mechanical gravel-pack equipment is placed in the well, the following job sequence generally applies: 1. Retrieve perforating guns from the well after perforating. 2. Run tubing string with an open-ended packer into the hole and set at desired depth. 3. Pressure test all lines to 1,000 psi over maximum anticipated job pressure. 4. Pressure the annulus and monitor that pressure throughout the fracturing job. 5. Perform the step-rate test by pumping completion fluid, if possible. The step-rate test should pump a pressure that exceeds the formation fracture gradient. A friction-reducer additive may be necessary to reduce wellhead pressure while pumping higher rates. 6. Shut down the pumps and allow the pressure to return to near-initial reservoir conditions. 7. Evaluate the step-rate test to determine the fractureextension pressure. 8. Perform the minifrac test by pumping the proposed fluid for a propped-fracture treatment at a constant rate. A step-down test may be performed as part of the minifrac test to determine if any fracture-entry restrictions are present. 9. Displace the minifrac fluid and shut down the pumps immediately. Monitor the pressure decline until fracture closure is observed. 10. Calculate the fluid-leakoff coefficient, closure pressure, closure time, fluid efficency, and friction pressure. Refer to Chapter 8 for procedures used to determine these coefficients and pressures. 11. Design a propped-fracture treatment that optimizes pumping rate, pad volume, and proppant schedule. 12. Pump the tip-screenout fracturing treatment until screenout occurs.

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13. Shut down the pumps when maximum pressure is reached and allow the fracture to close and the proppant to stabilize in the fractures. 14. Clean up the well slowly to allow the fractures and proppant to stabilize.

Chapter 15 INTRODUCTION Following FracPac stimulation, wireline logs can be run to help evaluate treatment effectiveness. Logs can determine the height of hydraulically induced fractures, verify the placement of pack materials, and analyze flow from treated formations. Tracer and production logs are the wireline services most commonly used for FracPac evaluation.

VERIFYING PLACEMENT OF PUMPED MATERIALS To verify the placement of pumped materials such as fracturing fluid, proppant, and gravel, spectral gamma ray tools such as Halliburton’s TracerScan tool are used. The materials to be pumped are tagged with radioactive tracers that have dissimilar gamma ray spectra. Each tracer emits gamma rays of different energies and different intensities than the other tracers. In a FracPac job, the fracturing fluid may be tagged with one tracer, the proppant with a second tracer, and the gravel with a third tracer. Since the TracerScan tool can distinguish gamma rays in different energy ranges, it can differentiate the tracers after they have been pumped downhole during FracPac operations. TracerScan logs record spectral gamma ray data as a function of depth and therefore can evaluate the vertical distribution of the tagged materials. This allows the total and propped fracture heights to be estimated and voids in gravel packs to be located. TracerScan data also give information regarding the approximate radial location of tracers and permits tracers in the borehole to be distinguished from tracers in the formation.

TracerScan logging is different from nonspectral tracer logging because TracerScan logging depends upon tracers with different gamma ray spectra rather than on tracers with different half-lives. A TracerScan log can be run on a single trip to the well immediately after FracPac pumping operations have been completed. This contrasts with the traditional nonspectral tracer logging that required several trips to the well days, weeks, and even months after the pumping operations.

Evaluation Logging

TracerScan Job Design Job design should involve the operating, pumping, tagging, and logging companies. The pumping program must be outlined, the information to be obtained from logging must be specified, and the tracers that will best meet the logging objectives must be selected.

Tracer Selection Tracer properties that must be considered in selecting tracers for a FracPac job include energy levels, spectral peaks, half-lives, and concentrations. The type and number of tracers are also important factors. TRACER ENERGY LEVELS – The distance that a gamma ray travels through matter depends upon the gamma ray’s energy level. High-energy gamma rays travel farther than low-energy gamma rays. A tracer is considered to be of low energy if most of its emitted gamma ray energies do not exceed 600 keV. Low-energy tracers are best used in the near-wellbore region and in tail-in material at the end of a pumping operation. When tracers

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Table 15.1 — Common Tracers Used in Hydraulic Fracturing

Tracer

Isotope

Half-Life (days)

Gold-198

198Au

2.70

Iridium-192

192Ir

Antimony-124

Scandium-46

124Sb

46Sc

74.00

60.20

83.80

are at some distance from the wellbore, high-energy tracers (those with most gamma ray energies exceeding 600 keV) are more easily detected than are low-energy tracers. Thus, high-energy tracers, especially those with energies above 1,000 keV, are more suitable for tagging materials used during the early stages of fracturing operations. Table 15.1 gives energy levels and half-lives of several tracers used in evaluating fracturing and gravel packing operations. TRACER SPECTRAL PEAKS – When more than one tracer is used, the gamma ray spectra of the tracers must be considered. The major gamma ray peaks in each spectrum must be sufficiently different from those in the other spectra so that the tracers can be easily distinguished from one another. Figures 15.1 and 15.2 show the spectral peaks of two tracer combinations. One of these combinations is suitable for TracerScan work, and the other is not. NUMBER OF TRACERS – In general, the minimum number of tracers should be used to evaluate the FracPac treatment. As the number of isotopes that are used increases, it becomes more difficult to spectrally differentiate the isotopes. It also becomes more difficult to determine precisely the concentrations and the radial-distance indicators. TRACER HALF-LIVES – Tracer half-lives should be long enough so that if there are reasonable job delays, it should not be necessary to obtain additional tracers. Tracers with half-lives on the order of 60 days are commonly used, but specific jobs may require shorter or longer times. 158

Gamma Ray Energy (keV)

Gamma Ray Intensity

Energy Level

412

0.96

Low energy

676

0.01

311

1.42

468

0.48

603

0.18

606

1.05

720

0.15

1,353

0.05

1,691

0.49

2,091

0.06

889

1.00

1,121

1.00

Low energy

High energy

High energy

TRACER TYPES – In 1992, TracerScan log interpretation was enhanced by the introduction of zero-wash tracers, also known as zero-leach tracers. Before zero-wash tracers became available, tracers were prone to wash off the tagged material or to plate out on tubular assemblies. This caused abnormally high tracer concentrations in the borehole. The new technology has eliminated the wash-off and plating tendency for solid tracers; however, except for scandium, liquid tracers still exhibit this characteristic. Nevertheless, liquid tracers can be used successfully, but it is critical that the tagging agent be chemically formulated so that preferential deposition of the tracer will occur in the formation and not in the borehole. TRACER CONCENTRATIONS – There is a natural variation in the intensity of gamma rays emitted by tracers; thus, TracerScan measurements will exhibit statistical variations. Tracer concentrations on tagged materials must be high enough to minimize these statistical variations in TracerScan measurements but must be low enough to not distort tool response. Spectral gamma ray tools are designed for a linear response up to a certain maximum gamma counting rate (generally between 2,000 and 5,000 API units); higher rates degrade the response. Tracer injection rates are commonly a few tenths of a millicurie per 1,000 gallons of fluid (a few megaBecquerels per cubic meter of fluid, or a few hundredths of a megaBecquerel per kilogram of solid). These rates usually result in gamma ray measurements of a few hundred to a few thousand API units.

Radioactive Tracer Spectra

Radioactive Tracer Spectra

Well-Separated Peaks

Poorly Separated Peaks

192Ir

100 80 60 40 20

192Ir

120

46Sc

Relative Intensity

Relative Intensity

120

131I

100 80 60 40 20

200

600 1,000 1,400 Gamma Ray Energy (keV)

1,800

200

600 1,000 1,400 Gamma Ray Energy (keV)

1,800

Figure 15.1 — Iridium-192 and scandium-46 are an excellent pair of tracers for use in TracerScan operations since their spectral peaks are well separated.

Figure 15.2 — Iridium-192 and iodine-131 are not a good pair of tracers for TracerScan work. Some of the spectral peaks are not well separated; therefore, the tracers are difficult to spectrally isolate.

Since the gravel is concentrated in the borehole and the fracturing fluid and proppant are dispersed in the formation, care must be taken in selecting the tracers and their concentrations so that gamma rays from tracers in the formation are not obscured by gamma rays from tracers in the borehole. It is also important that the tagged components of the FracPac job be pumped in a manner that is representative of the FracPac operation as a whole.

Data Quality Considerations

Table 15.2 shows guidelines for selecting tracers for a typical FracPac completion.

Several measures can be taken to ensure that the information obtained from TracerScan logs is of the highest quality possible. In general, these measures increase the accuracy of measured data and reduce the number of interpretation possibilities. First, information from other logs, especially gamma ray and sonic, is helpful. Although not required, a TracerScan log can be run before a FracPac job to measure the background gamma radiation that must be subtracted from the later tracer measurements. When such a prejob TracerScan log is not run, the background gamma ray is estimated from the postjob log.

Table 15.2 — Typical Tracer Design for FracPac Completion Fracturing Phase

Recommended Tracer

Tracer Form

Tracer Concentration

Pad

Scandium-46

Liquid or

0.4 mCi/1,000 gal

100-mesh zero-wash

(tracer/pad)

particles Sand to tip screenout

Antimony-124

Zero-wash particles

0.4 mCi/1,000 gal

(or Scandium-46 if

sized to sand size

(tracer/sand)

Zero-wash particles

0.25 mCi/1,000 gal

sized to sand size

(tracer/sand)

pad is not tagged) Cut crosslinked gel through pack

Iridium-192

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TracerScan Log 0

Iridium Gamma Relative Distance Far 1000 API 200 Near Scandium Relative Distance Near

Far 1000

Iridium Formation API

0

Scandium Formation API

0

Collar Locator 1000

Iridium Formation API

0 0

Scandium Total API 1000 0

Iridium Total API

Scandium Formation 1000

API

0

Scandium Scandium Scandium X600 Iridium Collar Locator

Iridium Iridium Gamma X650

X700

X750

160

1000

Next, to reduce the statistical variations associated with the measurements that are used to calculate the radial-distance indicator, multiple logging runs should be made over the zone of interest. Typically, three to five passes are made at a logging speed of 10 ft/min. Finally, all information pertaining to the placement operation should be carefully documented. This documentation should include the planned program and the actual program. The tracers used, their injection rates, and the type of tagging agent should be listed.

TracerScan Log Evaluation For each tracer used, TracerScan logs can display the gross measured gamma ray count rate, a relative-distance curve, a borehole component, and a formation component. In evaluating a TracerScan log run on a FracPac completion, the relative-distance curves are the most useful. These curves are used in a qualitative sense, with low values indicating that the tracer is “near” the borehole and high values indicating that the tracer is “far” from the borehole. Figure 15.3 shows a TracerScan log used to determine the placement of fracturing fluid and proppant.

PRODUCTION LOGGING Production Logging gives quick and accurate flow information at the wellsite. Reliable results can be obtained in both single-phase and multiphase flow, whether in vertical or deviated wells. Production Logging flow profiles can be used to evaluate the effectiveness of a FracPac treatment and can diagnose production problems such as leaking tubulars and crossflow between zones. Halliburton’s wellsite Production Log Analysis (PLA) program uses fluid dielectric, fluid density, flowmeter, temperature, pressure, and optional gradiomanometer data and gives results identical to those obtained at computing centers. The program determines average fluid velocity; oil, gas, and water holdups; and the downhole and surface volumetric flow rates of the fluid components. Quality

indicators on the PLA log help in judging the correctness of the calculation models and in optimizing parameter selections for the calculations. As shown in Figure 15.4, Halliburton’s production logging tools can be combined for multiple measurements in a single logging run. Toolstrings can be run on wireline in conventional wells and on drillpipe workstring or coiled tubing in deviated wells. Additional services are available for confirming, refining, and expanding some of the information provided by the primary services. The additional services include Borehole Audio Tracer surveys, radioactive fluid travel logs, and Thermal Multigate Decay logs.

Measuring Fluid Characteristics Production logging measurements allow analysts to determine the fluid components that are present in the flowstream and the velocity of each component.

Fluid Components Wellbore fluids can be described by the phases, or components, that are present (i.e., water, oil, and gas). For a particular phase, the holdup at a given depth in the well is the fractional cross-sectional area of the pipe occupied by that phase. The Hydro and fluid density tools provide the information for calculating holdups. At least one of these tools is needed to calculate two-phase holdups, and both tools are required for three-phase calculations. Another device, the gradiomanometer, can be used in place of the fluid density tool. HYDRO TOOL – Halliburton’s Hydro tool, also known as the fluid dielectric, capacitance, or watercut tool, is sensitive to the dielectric constant of the flowstream. Wellbore fluids flow through a tool chamber and affect the frequency of an oscillator in the tool. Low frequencies correspond to high-dielectric-constant fluids (water), and high frequencies correspond to low-dielectric-constant fluids (hydrocarbons). Consequently, the Hydro tool can distinguish between water and hydrocarbons, but it may not be able to distinguish between oil and gas because the frequency differences

Figure 15.3 (opposite page) — This TracerScan log was run to evaluate the effectiveness of hydraulic fracturing operations. The fracturing program was designed to suitably limit the vertical extent of the propped fractures so that zonal isolation could be maintained. The pad was tagged with scandium-46 and the proppant with iridium-192. On the log, the gamma ray concentrations of both isotopes indicate that each of the three intervals remained isolated. The scandium relative distance curve reveals that fractures in each zone extended beyond the perforated intervals, particularly in the upper zone where the fractures propagated more than 50 ft above the perforations. However, the iridium relative distance curve confirms that the propped intervals did not communicate with one another.

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Production Logging Toolstring Gamma Ray

Flowmeter

Telemetry

Fluid Density

Centralizer

Hydro

Collar Locator

Temperature

Pressure

Figure 15.4 — This production logging toolstring contains all the components necessary to evaluate threephase flow. The gamma ray and collar locator subassemblies provide information for accurate depth correlation. The fluid density and Hydro devices furnish data for identifying the fluid components in the flowstream, and the flowmeter measures the velocity of the flowing fluid mix. The pressure and temperature tools supply particulars needed for PVT analysis.

between the two hydrocarbon phases are small. The tool is calibrated so that water holdup can be calculated from oscillator frequency. FLUID DENSITY TOOL – The fluid density tool measures the density of the flowstream. Wellbore fluid flows through a tool chamber that has a gamma ray source at one end and a gamma ray detector at the other end. The denser the wellbore fluid, the fewer gamma rays reach the detector. Thus, low detector count rates correspond to high fluid density, and high detector count rates correspond to low fluid density. The tool is calibrated so that fluid density can be calculated from the detector count rate. GRADIOMANOMETERS – Gradiomanometers also measure fluid density. They contain an internal float system filled with a special fluid. The pressure difference between two points in the system is measured and used to determine a pressure gradient, which in turn is converted to fluid density. Gradiomanometer measurements must be corrected for hole inclination, whereas measurements from fluid density tools do not require such a correction.

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Fluid Velocity Spinner flowmeters, whether of the continuous, fullbore, or diverter type, provide information related to the average velocity of the fluid mix in the well. The wellbore fluid velocity (both speed and direction) is calculated from the spinner’s rotational speed and direction. CONTINUOUS FLOWMETERS – Continuous flowmeters contain a helical impeller, or spinner, with diameter slightly less than that of the toolbody. These flowmeters are designed for use in wells with moderate to high flow rates and in wells containing tubing or small-diameter casing. FULLBORE FLOWMETERS – Fullbore flowmeters contain collapsible spinners that, after passing through tubing into casing, open to a diameter larger than that of the toolbody. These flowmeters are intended for use in wells with low fluid velocities (common in larger casing sizes) and in deviated wells where phase separation in the flow stream may occur. DIVERTER FLOWMETERS – Diverter flowmeters contain an expandable metal basket that diverts wellbore flow through the center of the tool where a spinner is located. These tools are used in both inclined wells and in wells with low flow rates. They are generally held stationary while making their flow measurements.

Fluid Volume and State As fluid flows through the wellbore, temperature and pressure change, affecting the volume and state (liquid or gas) of the fluid. Thus, the volume and state of a fluid entering or leaving the wellbore downhole can be very different from the volume and state of the same fluid at the surface. The analysis of fluid volume and state changes that occur with temperature and pressure changes is called pressure-volume-temperature (PVT) analysis. Pressure and temperature measurements are needed in PVT analysis and are also useful in studying reservoir characteristics and in locating zones that are producing or accepting fluids. PRESSURE TOOLS – Both strain gauges and quartz transducers are used in production logging pressure tools. Strain gauges respond more quickly to pressure changes, and thus are used when real-time pressure measurements are needed. On the other hand, quartz transducers have higher accuracy and therefore can give superior data for analyzing pressure drawdowns and buildups. TEMPERATURE TOOLS – Temperature tools use a resistance thermometer to measure wellbore temperature. A resistive element that is part of an electrical circuit is exposed to wellbore fluids; changes in fluid temperatures cause changes in the element’s resistance. Fluid entering the wellbore, or fluids leaving the wellbore and accumulating in the region surrounding the wellbore, can alter the normal temperature gradient in the well. The resulting temperature-gradient anomalies can be used to identify producing zones, locate zones that are accepting fluid, and detect channeling from above or below.

Fluid Movement Behind Pipe Several tools can give information about fluid movement behind pipe. These include the Borehole Audio Tracer tool, the Thermal Multigate Decay tool, the Pulsed Spectral Gamma tool, and Radioactive Fluid Travel tools. BOREHOLE AUDIO TRACER TOOL – The Borehole Audio Tracer tool senses noise created by fluid movement in and around the borehole. The tool is held stationary while measurements are being made. This eliminates noise that would occur as a result of tool motion. The logging system records the maximum amplitude in each of four frequency ranges extending from 200 Hz, 600 Hz, 1,000 Hz, and 2,000 Hz up to the maximum frequency to which the tool is sensitive. On the log, amplitudes are plotted versus depths, and individual points in each of the frequency ranges are connected to produce the four noise curves. The log is used to locate fluid flow, identify fluid type,

and give information about the type of passage through which the fluids are flowing. THERMAL MULTIGATE DECAY AND PULSED SPECTRAL GAMMA TOOLS – A pulsed neutron source in the lower part of Halliburton’s Thermal Multigate Decay and Pulsed Spectral Gamma tools irradiates oxygen-rich fluids such as water and CO2 to produce a radioactive isotope that quickly decays and emits gamma rays. If the fluid is flowing upward at a speed greater than the logging speed, the gamma rays can be sensed by detectors in the upper part of the tool. Thus, the tool can be used to detect upward fluid movement (both inside and outside casing), to determine vertical fluid velocities, and to locate fluid entry and exit points in the wellbore. Logging speed adjustments allow upward fluid movement to be detected over a wide range of borehole and annular cross-sectional areas. RADIOACTIVE FLUID TRAVEL TOOL – The Radioactive Fluid Travel tool determines fluid velocities by measuring the time required for a tagged wellbore fluid to travel between two gamma ray detectors. Wellbore fluids are tagged with a small amount of radioactive fluid ejected from the tool into the flowstream. This tool is useful in wells with fluid velocities too low to use a spinner flowmeter and in wells where it is desired to diagnose vertical flow behind casing.

Analyzing Fluid Flow The computer-assisted Production Log Analysis program contains options that allow the analyst to combine production logging data with related wellbore and formation data.

Data Averaging The PLA program can average production logging measurements by depth or by zone. Zoning a well allows spinner calibration plots to be used to establish spinner threshold velocities, which in turn are necessary to calculate average fluid velocity. It is advisable to average the fluid density and Hydro logs from multiple passes to reduce statistical variations that may be present in the data. Stabilized flow is required when these passes are made.

Determining Average Velocity The PLA program uses one of two methods to determine average fluid velocity from cable speeds and spinner rates. When multiple logging passes have been made over the zone of interest, the Chi-square method is used. When only a single pass has been made over the zone, a linear

163


regression method is selected instead. Over discrete depth intervals, the program automatically removes anomalous spinner data that do not match the velocity profile. The log displays quality indicators that show where such data were removed.

Analysis Display The PLA program produces an informative, easy-to-read display of wellbore flow characteristics. The display shows holdups and surface flow rates for each fluid phase at standard pressure and temperature conditions. Downhole flow rates can also be plotted, and the gas flow rate can be subdivided into that attributable to gas coming out of solution and that attributable to gas existing in the free state. A wellbore sketch gives a clear picture of the completion. It displays as many as four casing or tubing strings, along with slotted liners, packers, sliding sleeves, gravel packs, and perforations. Figure 15.5 shows the data recorded during multiple passes of a production logging string. Figure 15.6 shows the result of applying the PLA program to that data.

Figure 15.5 (opposite page) — This production log was obtained by making eight passes in a flowing well. The wireline cable speeds are shown in the second track from the right and indicate that four upward passes (dashed curves) and four downward passes (solid curves) were made through the well. Spinner rotational speeds for the passes are displayed in the rightmost track and clearly indicate the entry of fluid into the wellbore over the three perforated intervals shown in the wellbore sketch. The temperature and pressure curves plotted to the left of the sketch reflect an almost linear variation of the two parameters with respect to depth. The fluid density curve presented to the right of the sketch indicates a change in wellbore fluid density at the bottom part of the lowermost set of perforations.

164

Production Log

165


Production Log Analysis

Figure 15.6 — The production logging data of Figure 5 were analyzed with the PLA program to obtain these results. The holdup curve in the leftmost track indicates that there was two-phase production. In the three tracks to the right of the wellbore sketch are three production presentations: (left to right) cumulative production as a continuous function of depth, cumulative production averaged over each of the three perforated intervals, and individual production from each of the three intervals. Note that all three intervals produced oil at about the same rate, but the upper interval produced much less water than the lower two.

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Chapter 16 INTRODUCTION The case histories in this chapter are included to illustrate the entire process of FracPac Completion Services. Where pretreatment production data were available, they are used to contrast the results after a FracPac treatment. Cases from both the Gulf of Mexico and West Africa are included to show the versatility of FracPac Completion Services in all types of poorly consolidated, high-permeability reservoirs.

CASE HISTORY NO. 1 LOCATION – This offshore-Louisiana well was completed at 6,000 ft in a relatively low-permeability (10- to 50md) pay zone with approximately 100 ft of gross pay. PROCEDURES – After perforating at 12-spf in underbalanced conditions, the pay zone was acidized with 1,000 gal of hydrochloric acid containing an ironcontrol additive. A step-rate test and minifrac test were performed using 80-lb/Mgal linear HEC gel. Fluid efficiency was determined to be approximately 45% with fractureclosure pressure of 4,000 psi. A screenout design was planned on a pseudo-3D fracture simulator. The following pumping schedule (see Table 16.1) was followed during the treatment. A 5,000-psi increase in bottomhole pressure indicated that screenout had occurred, and that

proppant was packed to the wellbore. The total volume of 20/40 synthetic proppant placed was approximately 33,000 lb (See Figure 16.1).

Case Histories

RESULTS – Since this well was originally gravel packed, the results from a postcleanup-buildup test were startling. A negative skin factor was achieved, which was very unusual for a gravelpacked well in this area. The negative skin factor indicates that the nearwellbore damage from the original gravel pack was bypassed and that a relatively low-permeability formation benefitted from the stimulation.

CASE HISTORY NO. 2 LOCATION – This offshore-Louisiana well was completed at about 10,000 ft in a high-permeability formation (500 to 1,000 md). The pay zone grossed approximately 50 ft. PROCEDURES – After the well was perforated in underbalanced conditions at a 12-spf, a step-rate and a minifrac test were performed to gather input data for a propped fracture design. Refer to Figure 16.2 for a log of the FracPac treatment performed. Fractureclosure pressure was determined and a net-pressure match was obtained using a pseudo-3D design simulator. A fluid efficiency of 10% was calculated, and the treatment schedule that follows (see Table 16.2) was designed accordingly.

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Table 16.1 — Case History No. 1 Pumping Schedule Clean Volume

Proppant Concentration

Cumulative Proppant

Stage

Event

(gal)

(lb/gal)

(lb)

1

Pad

500

0

n/a

2

Proppant

1,000

2

2,000

3

Proppant

2,500

2 to 12 ramp

19,500

4

Proppant

1,150

12

+ 33,000

5

Flush

n/a

n/a

n/a

Case History No. 1 15

16

18

19

20

9

18

8

16 Slurry Rate

7

psi (1,000)

17

14

6

12

5

10

4

8

3

6

PConc/Slurry Annulus Pressure

2

4

Tubing Pressure

1

2 0

0 4

8

12

16

20 Time (min)

24

28

32

36

Figure 16.1 — A new completion, offshore from Louisiana, was perforated at 12 spf in underbalanced conditions. The pay zone was first acidized, then a step-rate test and minifrac test were performed. An 80-lb/Mgal linear HEC gel was used to place 33,000 lb of proppant. A negative skin factor was achieved, which was highly unusual in this unconsolidated formation.

168

bbl/min (slurry rate) lb/gal (proppant concentration)

13 14

10

Table 16.2 — Case History No. 2 Pumping Schedule Clean Volume

Proppant Concentration

Cumulative Proppant

Stage

Event

(gal)

(lb/gal)

(lb)

1

Pad

15,000

0

n/a

2

Proppant

7,000

0.5 to 4.0 ramp

16,000

3

Proppant

3,500

4.0 to 12.0 ramp

36,000

4

Proppant

1,000

12

48,000

5

Flush

n/a

n/a

n/a

Case History No. 2 6

250

BHP (Gauge) Slurry Rate

psi (1,000)

4

3

200 BHT (Gauge)

Tubing Pressure

150

2

100 PConc/Slurry PConc/Bottom

1

bbl/min (slurry rate) lb/gal (proppant concentration)

5

300

50

0

0 10

20

30 Time (min)

40

50

Figure 16.2 — Another offshore-Louisiana well in a high-permeability formation was treated with FracPac. The well was perforated at 12 spf, and a step-rate and minifrac test were performed. A 40-lb/Mgal borate-crosslinked HPG was pumped according to a staged schedule. Response from the well was a production rate of 10 MMcf/D with very low drawdown, results typically unheard of from wells in this area.

169


Step Rate Test 7,000 ellhead Pressure (psi)

5,000

Rate (0 to 20 bbl/min)

18:37:06

Fracture Extension @ 1.1 bbl/min, 5,930 psi Wellhead Pressure Roughly 9,360 psi Bottomhole Pressure (Excluding Friction)

4,000 0

1

2

3

4 5 6 7 Rate (bbl/min)

18:29:06

8

9

Tubing Pressure

10 11

18:45:06

Figure 16.3 — Fracture-extension pressure is determined from a step-rate test. This test used 70 bbl of water that was pumped at 0.3 to 8.0 bbl/min after formation breakdown occurred.

Proppant Concentration (0 to 10 lb/gal) S2 S3

18:53:06 (0 to 15,000 psi)

19:01:06

S4

Pressure vs. Square Root of Shut-In Time Plot

19:09:06 S5

5,400 Wellhead Pressure (psi)

Time (h:m:s)

6,000

W

Bottom Hole Pressure Calculated (0 to 15,000 psi)

S6 S7

19:17:06

5,200 19:25:06 5,000 19:33:06

4,800 4,600 4,500 0

10 20 30 Shut-In Time (min)

40 50 60

Figure 16.4 — Fracture closure pressure and closure time are determined from a minifrac test. Relatively small fluid volumes, as compared with the main fracturing treatment, are pumped. Fluid efficiency in this test was calculated at 25% to 35%.

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Figure 16.5 — The pressure log from the main treatment tells both operators and clients how the formation is responding to the treatment, and whether the treatment matches the design. The fracture design for this well was developed from minifrac data. A designed stage of 36,000 lb of intermediate-strength, 20/40 proppant was pumped. The well screened out at 33,000 lb.

This well happened to have existing bottomhole gauge information available, and a gravel-pack packer and screen assembly were already installed. The treating fluid used was a 40-lb borate-crosslinked HPG, and a 20/40 synthetic proppant was used. Pumping rates for the job were 25 bbl/min. RESULTS – The well responded with a 10-MMcf/D production rate with very low drawdown, which was very unusual for wells of this area.

CASE HISTORY NO. 3 LOCATION – This offshore -Texas gas well was deviated and completed at 12,000 ft (10, 300 TVD). The formation was a 10-md sandstone with a gross pay zone height of 80 ft. WELL DESCRIPTION AND PROCEDURES – From the bottom of the well at 12,100 ft MD (10,000 ft TVD) to 10,500 ft MD (9,400 ft TVD), 5-1/2-inch liner was in place. Intermediate casing was in place from 10, 500 ft MD to the surface. A tapered workstring was deployed using 3-1/2-inch tubing from the surface to 7,200 ft MD and 2-7/8-inch from 7,200 ft to 10,450 ft, where the sealbore packer was set. Because of the limited amount of seal area on the casing wall, there was concern about how much the tubing string might contract during the treatment. All treating fluids were heated to minimize the temperature differential and the contracting effect it has on the tubing string. A step-rate test was performed. The step-rate test used 70 bbl of treated water, which was pumped at rates from 0.3 to 8.0 bbl/min after breakdown occurred. Fractureextension pressure was determined from this test as is shown in Figure 16.3. A 150-bbl minifrac test was also performed. A 40-lb/Mgal borate-crosslinked HPG fluid was pumped at 10 bbl/min. Fracture-closure pressure and closure time were determined from the minifrac test and are shown in Figure 16.4. Fluid efficiency was calculated at 25% to 35%. The propped-fracture design was developed from the data acquired in the minifrac test. A pad volume of 300 bbl of 40-lb/Mgal borate-crosslinked gel was pumped at 10 bbl/ min. The pad was followed by a proppant stage of 36,000 lb of intermediate strength, 20/40 synthetic proppant. Screenout occurred after 33,000 lb of proppant were placed in the formation, as shown in Figure 16.5.

2 MMcf/D. A postjob-buildup test showed the well to have less than a 5 skin, with production rates of 10 MMcf/D.

CASE HISTORY NO. 4 LOCATION – A major producer in West Africa wanted the benefits of fracture stimulation and the protection of sandcontrol techniques combined to reduce skin and maximize production from 7 new wells in a field to be developed. Sand control and high production rates were of primary importance to the operator, since these wells promised excellent production potential. Previously, hydraulic fracturing was considered unnecessary in such high-permeability formations. However, when the operator realized the long-term benefit in production that FracPac offers by incorporating fracturing and sand control, they were eager to apply this technique. WELL DESCRIPTION AND PROCEDURES – In the first well of the series, two producing intervals were completed. A linear HEC gel and 20/40 synthetic proppant were pumped into both of the intervals. Both fracture treatments were performed and a gravel pack was placed over the entire interval. Production results were good, with a skin factor measured below 2.0. The successful results in this first well prompted the decision to use FracPac techniques to complete the remaining wells in the project. In the second well treated, borate-crosslinked fluid was used. This type of fluid performed much better in the high-permeability zones by controlling fluid loss. The discovery of less fluid loss with borate-crosslinked fluids led to dual-fluid systems being pumped where highpermeability zones were encountered in other wells. In such wells with high-permeability zones, a boratecrosslinked HPG was pumped as a pad volume to initiate the fracture. The proppant stage of the treatment was then placed with linear HEC gel, to ensure maximum fracture conductivity. This dual-fluid technique was most effective in placing large volumes of proppant into the wells. RESULTS – The proppant-packed fractures in these WestAfrican wells have proven very effective in reducing skin and increasing production, while providing excellent sand control.

RESULTS – A prejob pressure buildup test determined that the well had a 30+ skin and was producing approximately

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HBL FracPac Completion Service

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