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This workbook is a practical companion to the second edition of the textbook Reservoir Stimulation. The two books are intended to be used.
Table of contents

Powered by Koha. Log in to your account. Advanced search Tag cloud. Login: Password:. By: Economides, Michael J. Material type: Text Series: Developments in petroleum science : Amsterdam : Elsevier, Description: Paginas variada : ilustraciones ; 29 x 21 cm. If the tem- for the fracturing fluid selection to the detriment of fracture perature is less than "F, then all fracturing fluids can be conductivity.

This issue is discussed extensively in Chapter used with the obvious considerations of diminishing perma- 11 of Reservoir Stimulation. The time dependency occurs because of fully transport proppant throughout the fracture. When de- the delayed crosslink nature of these fluids. These are some signing a fluid to meet this requirement, the reservoir static of the most common fracturing fluids and the ones recom- temperature must be taken into account.

As shown in Fig. The latter has been at this temperature. Figure P shows the es, polymer loading may be reduced because this portion of apparent viscosity of these fluids and their substantially lower the treatment will not be exposed to reservoir temperature for values when compared to the crosslinked liquid fluids. These an extended period of time. The latter can be whereas Figs. P through P contain the same informa- readily obtained using the method outlined in Table In both cases, three quality foams are used: Example calculations are shown in Chapter C of this volume.

Large differences will be observed at low flow rates in small-diameter tubings. Figures P-3 1 through P contain the friction pressure drop for lb, lb and lb zirconates, respectively. Thus, experimental data are necessary, especially in Figures P through P contain friction pressure drops turbulent flow. Figure P provides the friction pressure for lb bo- tubings, respectively.

Practical Companion to Reservoir Stimulation - E-bok - M J Economides () | Bokus

The dashed Friction pressure drops for foams are significantly larger lines are for completely delayed crosslinking, and the solid than for crosslinked liquid fluids. For example, if 20 BPM of lines are for nondelayed polymers. The observed break in the foam are pumped down 2x P and P provide friction pressure the friction pressure drop Curve 2 in Fig. P is equal to drops for foams pumped down annuli.

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Figure P contains the same data for lb It must be noted that the friction pressure drops for foams borate fluids. At 20 BPM downhole measuring devices. Conductivity tests similar to those described in Section ity more than lower polymer loadings.

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This second point is emphasized by the fact that foams of either Nz or CO- c 1ean up much better than standard water-base fracturing fluids. Table P-6 gives the results of similar tests performed at much lower temperatures. Even though the conductivity values P The fluids are subse- by different crosslinkers remains the same. These data indi- quently broken and allowed to clean up before permeability cate that when a water-base fluid is used, borate-crosslinked measurements are taken.

These tests confirm the earlier claims that guar is more damaging than HPG. However, the overall level of damage is significantly greater as polymer concen- trations increase. First, the viscosity of the fluid must be reduced so that the fluid can be cleaned up quickly following a treatment. Second, as demonstrated in Section P All common breakers perform both these tasks by attack- 70 ing the backbone of the polymer and reducing its size.

A Practical Companion to Reservoir Stimulation, Volume 34

As the molecular weight of the polymers decreases, so does the 60 fluid's viscosity. Table P-8 shows the concentration of con- 40 ventional breaker systems needed to break linear fluids when 30 the well can be shut in for 24 hr. The zyxw optimum pH for most enzyme breakers is 5.


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These breakers are effective over a wide pH range 3 to 14 and demonstrate superior breaking properties based on observed proppant-permeability reduction. Once a breaker is added to a based on fluid efficiency. Time- and temperature-dependent fracturing fluid, the degradation process immediately begins.

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If too much breaker is added early in the treatment, the never allowing the fracturing fluid to degrade below the viscosity required for fluid loss control and proppant transport critical viscosity of cp sec Table P- 10 gives a hy- may be prematurely lost, resulting in a screenout. If the pothetical treatment schedule using a lb borate-cross- breaker schedule is not ambitious enough, the molecular linked fracturing fluid.

The pad fluid will be degrade without sufficient breaker quantities, limiting well exposed to bottomhole temperature for more than 1 hr so only production because of proppant-conductivity damage. This is a minimal amount of breaker can be added. The last proppant particularly true at high polymer concentrations. As the poly- stage is exposed to bottomhole temperatures for less than 10 mer concentration increases, higher breaker concentrations min, allowing the breaker concentration to be very aggressive must be maintained to sufficiently degrade the polymer and for this one stage.

It is now recognized Breakers for oil-base gels operate much differently than that the in-situ polymer concentration in the fracture may their water-base counterparts. The breaker level in this they are intended to reverse the crosslinking reaction.

The breaker is dissolved into the water large quantities of breaker are required at lower temperatures. This can result in a damage to the often expensive because of the quantity of breaker needed. Amine systems can also be used in gelled oil systems to aid in Tapered breaker schedules allow much greater quantities the break process at low temperatures. To design the breaker schedule, the treatment has finished and the formation has closed on the time of exposure to bottomhole temperature for each stage of proppant.

The ideal breaker would then completely degrade the fracture treatment must be determined. From this, a the polymer in a very short period of time, and the fracturing maximum quantity of breaker can be calculated without fluid could be produced back. Recent advances in encapsula- risking premature loss of viscosity.

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This can best be demon- tion technology have allowed the development of breakers strated through the following example: Table P-9 gives vis- that perform in a similar manner. Even though the current cosity data for a borate fracturing fluid with breaker included. The fracturing fluids without sacrificing viscosity see Fig. Figure polymer inside the fracture. Once encapsulated, the breaker P can be used to estimate the temperature of a fracturing is large enough that it will not be lost during fluid leakoff.

Realizing that the Treatment Sizing net pressure is inversely proportional to fracture height helps explain the difficulty of containing fractures to very small P Large fracture heights are easier to confine because and Mass of Proppant the net pressure generated over a larger interval is much The optimum volume of fluid and proppant is best deter- smaller.

That chapter explains the optimization tainment unless relatively large fracture heights are obtained. The major parameters impacting the psi would be needed to contain a ft fracture with a gross net present value of a fracture treatment are the reservoir height of 20 ft. Stress barriers of this magnitude do not permeability, fracture height, fluid efficiency and residual generally exist.

However, if the fracture height is increased to damage to the proppant conductivity. A stress contrast of this magnitude is often found the volume of materials needed. Both fluid and proppant between sandstones and shales. Figure P is an example comparing total slurry fluid needed to obtain a given fracture length.

The parameter volumes needed to obtain a fracture half-length of ft that best quantifies efficiency is the leakoff coefficient. Fig- when fracture height increases. As fracture height doubles ure P shows that subtle changes in this fluid property can from 20 ft to 40 ft, the volume of slurry increases from 22, have dramatic effects on the volume of fluid needed to obtain gal to 66, gal.

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Before a treatment can be economically a given fracture length. By increasing the fluid loss coefficient optimized, it is obvious that some knowledge about the from 0. Although fluid loss , zyxwvutsrqpo zyxwv Fracture Length ft 10, zyx , , zyxwv 0.