Carbonate formation stimulation

8/17/2019 Carbonate formation stimulation

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Carbonate Matrix Acidizing Treatments

Introduction

Design guidelines for carbonate matrix acidizing treatments are limited at best. A review

of SPE literature 3,4 and commonly used reference manuals 5-9 provides little guidance

except for the most basic treatments. While several research groups (University of

Michigan,10-13 University of Texas,14,15 Mining University Leoben,16-18 Institute Francais

du Petrole,19-21 Halliburton 22,23) have studied acid reaction in porous media, few have

been able to apply this knowledge to treatment design. Many operators have presented

field studies that verify the most successful treatment techniques for their given areas.

These studies, while practical and useful, do not provide guidelines for optimizing

treatments. This Best Practices document provides guidelines for designing successful

matrix acidizing treatments.

Purpose of Matrix Acidizing

Matrix acidizing enhances well productivity by reducing the skin factor. The skin factor can

be reduced if near-wellbore damage is removed or if a highly conductive structure is

super-imposed onto the formation. In either case, the result is a net increase in the

productivity index (Q/DP), which can be used either to increase the production rate or to

decrease the drawdown pressure differential.

Although the benefits of an increased production rate are evident, the benefits of reduced

drawdown are often overlooked. Decreased drawdown can help prevent formation

collapse in weak formations, reduce water or gas coning, minimize both organic and

mineral scaling, and/or shift the phase equilibrium in the near-wellbore zone toward

smaller fractions of condensate or solution gas. A reduced drawdown pressure can also

help ensure that a greater percentage of the completed interval contributes to production.

Acidizing Considerations

Acidizing chemistry in limestone and dolomite formations is usually more direct and less

complex than in sandstone acidizing. A significant percentage of carbonate treatments use

hydrochloric acid (HCl). The dissolution products of the HCl-calcite or HCl-dolomite

reaction are completely soluble. Even in applications in which the formation is not

completely soluble, additives and acid systems can help suspend insoluble fines and


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particulates to prevent them from interfering with the treatment.

Additional design considerations include candidate selection, well completion, and

treatment design and execution. When horizontal wells or large intervals in carbonate

reservoirs must be treated, zonal coverage becomes a crucial, complicated design factor.

Candidate Selection

Carbonates tend to be significantly less homogeneous than sandstones. Large

permeability and porosity contrasts can exist in a single interval, often within a few feet or

inches. Figure 1 illustrates variations in rock structure in a single formation core. These

samples (both primarily calcite) were taken within 1 ft of each other, and are shown

under the same magnification (2000×). The variations in crystal size, the irregular pore

structure, and the significant difference in the visible porosity make uniform fluid

placement difficult.

In many carbonate formations, the presence of natural fractures is an important

consideration during reservoir or well evaluation. Natural fractures are visible in most

carbonate core samples brought to the surface. Under downhole conditions, however,

these fractures may not be productive if they are infilled or closed because of high

stresses. Pressure buildup tests or production history matches will not detect closed

natural fractures. Well logs may detect the fractures, even if they are closed, depending

on the logging techniques used. For more information about logging techniques for

natural fractures, see the Best Practices document, Natural Fracture Identification.

Figure 1: Variations in Rock Structure Within a Single Formation Core

Acidizing can effectively open natural fractures. Figure 2 shows photos of a naturally


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fractured formation core before and after etching with acid. In this case, the natural

fractures were infilled with a material of higher reactivity than the bulk of the core face.

The acid readily dissolved the infill material and effectively opened the fractures. Opening

natural fractures often accounts for the unexpected high production rates that occur after

some matrix acidizing treatments.

Figure 2: Acid Etching of Natural Fractures in a Formation Core

Matrix Acidizing Applications

Matrix acidizing should only be considered when the formation's native permeability can

provide hydrocarbon flow at economical rates after damage has been removed; it is not a

solution to poor reservoir quality. Typically, the lower permeability limit for matrix

production is about 10 md for an oil well, or about 1 MD for a gas well. These guidelines

are only general, since an evaluation of the permeability thickness is more appropriate

than an evaluation of permeability alone. In addition, fluid viscosity, multiphase flow, and

pressure influence well productivity.

Since the flow channels and pores in carbonates are acid-soluble, permeability can

increase significantly in the part of the formation that the acid contacts. As a result,

negative skin values are routinely observed when pressure tests are performed in

carbonate intervals that have been effectively acidized, contrary to the results observed

after matrix acidizing in sandstone formations, where an effective treatment results in

zero skin.

Acid can create long, dominant wormholes in carbonates; it cannot create wormholes in

sandstones. Therefore, acid can improve matrix permeability for several feet from the


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wellbore in carbonates but only for a few inches in sandstones. As a result, acid

treatments in sandstones only remove damage, while acid treatments in carbonates

remove damage and stimulate the well.

As shown in Figure 3, reducing the skin factor from 5 to 0 has a bigger impact on the

production of a typical oil well than reducing it from 25 to 20. Reducing the skin factor

below zero has significantly more impact on well productivity. This simple example is

powerful; recognizing that the skin/productivity relationship is nonlinear is fundamental to

effective candidate selection and optimized treatment design.

Figure 3: Oilwell Productivity As a Function of Skin Value

Two curves are shown in Figure 3, one for a ratio of drainage radius (Rc) to wellbore

radius (Rw) of 6,400 and the other for a ratio of 640. For positive skin values, drainage

radius has little influence on the relative productivity curve. For negative skin values, as

the drainage radius decreases, the influence of skin increases. The smaller the well

spacing, the greater the benefit of the negative skin resulting from matrix acidizing in

carbonate formations.


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Table 1 illustrates the magnitude of skin normally associated with various types of

completions/stimulations in carbonate formations. Similar tables have been presented by

Fair1 and Spivey et al.2 To determine the most appropriate treatment for a carbonate

formation, engineers must base the design on the magnitude of skin reduction necessary

after the formation is stimulated.

Table 1: Skin Factors for Various Completions or Stimulations

Types of Matrix Acidizing Treatments

Four types of matrix acidizing treatments can be performed: wellbore cleanouts, near-

wellbore stimulations, intermediate matrix stimulations, and extended matrix acidizing

treatments.

Wellbore Cleanout

A wellbore cleanout (WCO) treatment connects the wellbore to the formation. In

openhole, slotted, or preperforated liner completions, this treatment generally involves

removing mud and filter cake. In cased completions, the treatment usually consists of

perforation cleanup and/or breakdown. Wellbore cleanout treatments include spotting,

soaking or circulating acid, or small bullhead treatments that could momentarily exceed

fracturing rates. Volumes typically range from 10 to 25 gal/ft.

Near-Wellbore Stimulation

Near-wellbore stimulation (NWS) is achieved through matrix treatments that generally

use acid volumes of 25 to 50 gal/ft of interval. If properly designed, these treatments

typically improve the permeability within 2 to 3 ft of the wellbore and may result in skin

factors ranging from 0 to -2.


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Intermediate Matrix Stimulation

Intermediate matrix stimulation (IMS) treatments use acid volumes of 50 to 150 gal/ft of

interval. If properly designed with adequate diversion, these treatments typically improve

the permeability within 3 to 6 ft of the wellbore, and may result in skin factors ranging

from -2 to -3.

Extended Matrix Acidizing

Extended matrix acidizing (EMA) treatments are complicated and use larger volumes of

acid than other treatments-often as much as 150 to 500 gal/ft of interval. If applied

properly in the correct formations, however, EMA treatments can result in production

improvement comparable to hydraulic fracturing. These treatments may result in skin

factors from -3 to -5, depending on the density of natural fractures, matrix porosity,

acidizing fluids used, acid volumes, and the zonal coverage method.

Candidate Selection and Treatment Justification

The high degree of reservoir uncertainty caused by the heterogeneous nature of

carbonate formations makes candidate selection difficult. If multiple wells are being

evaluated, they should be ranked according to skin or productivity index (Q/DP). High-

skin wells are obvious choices for matrix stimulation. The productivity index must be

normalized for zone thickness to help differentiate between deliverability problems caused

by damage, and low productivity caused by poor permeability. The "Well Select" option

under Stim 2001 provides a useful tool for ranking multiple stimulation candidates.

When evaluating a single well, service engineers must review the well's history and

reservoir parameters to determine if it 1) is a stimulation candidate, 2) should be matrix-

or fracture-acidized, and (3) which (if any) matrix treatment is most appropriate. See the

Candidate Selection for the Stimulation of Carbonate Formations Best Practices document

for data-gathering templates and a concise candidate selection/evaluation process

decision tree.

RESULTS Program

D e s c r i p t i o n

Halliburton's RESULTS program is useful for determining whether treatments are justified.

RESULTS is a Windows-based, single-phase, analytical simulator that was developed

primarily for well-test design. It can provide quick, consistent simulations of radial and

fractured production (or injection) in vertical or horizontal wells. The effect of skin

damage or stimulation on a well's performance can be evaluated under multiple scenarios.


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The basic procedure includes the following steps:

1. Model the production (or injection) rate at a given set of conditions.

2. Compare various skin factors, using several positive and negative values.

3. If the interval is large, evaluate the effect of partial zonal coverage duringstimulation.

4. Compare to the predicted production rate following acid fracturing, if applicable.

Ex am p l e

The following example illustrates how the RESULTS program can help users select

treatment type. A typical continental North American oil well with a moderate depth,

pressure, temperature, permeability, and zone thickness contains a small, high-

permeability (thief) zone at the top. Below that zone is a much larger, lower-permeability

interval. During drilling, the upper interval is severely damaged while the lower interval

experiences only shallow, insignificant damage. Pertinent reservoir data used in the

RESULTS simulation is included in Table 2.

Table 2: Reservoir Data in RESULTS

Figure 4 presents the anticipated flow rates, compared under the same drawdown

pressure, for the well in its initial damage state and following four different treatment

scenarios. After 3 months with no acidizing, the production is approximately 170 BOPD.

Four scenarios for acid treatment are compared:

1. Only the large, low-permeability interval is treated, resulting in Skin2 = 0 (Skin

1

remains at 25).


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2. Only the small, high-permeability interval is treated, resulting in Skin1 = 0 (Skin

2

remains at 1).

3. Both intervals are treated for damage removal, resulting in Skin1 = Skin

2 = 0.

4. Both intervals are treated for stimulation, resulting in Skin1 = Skin

2 = -2.

Figure 4: Acidized Productivity Compared to Damaged Productivity

The RESULTS program predicts the well's production at 3 months to be approximately 185

BOPD, 250 BOPD, and 265 BOPD for the first three scenarios, illustrating the importanceof zonal coverage. If the high-permeability interval was so severely damaged that the acid

could not enter that zone to remove the damage (Scenario 1), then little production

increase would be achieved. On the contrary, if the high-permeability interval acts as a

thief zone and no attempts at diversion are made, then damage removal from the tighter

zone may not be achieved (Scenario 2). A notable production increase is achieved, but

recovery of the reserves in the lower-permeability interval may be sacrificed.

Scenario 3 represents a wellbore cleanout treatment with good zonal coverage. In this

case, damage removal resulted in a skin factor of 0 in both intervals. The benefit of true

stimulation, such as when the skin factor is reduced below 0 to -2 (Scenario 4) illustrates

the benefit of a near-wellbore stimulation treatment. In this case, the superposition of a

higher-permeability region around the wellbore resulted in an approximate two-fold

increase of production from the original damaged production of 170 BOPD to 350 BOPD at

Skin = -2.

Design Process


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The most common matrix acidizing treatments include 15 to 28% HCl combined with the

required system additives. Generally, treatment volumes range from 50 to 200 gal/ft of

interval. The treatment is pumped at the highest rate possible without fracturing the

formation. The injection rate varies, depending on formation conditions. In low-volume

treatments, pickling the tubing can improve treatment results. Spotting acid ahead of a

bullhead treatment can also enhance treatments. If possible, some type of acid diversion

treatment should be performed; if no attempts at diversion are made, zonal coverage is

often very poor. When possible, coiled tubing should be used for placing the treatment,

especially in large intervals and horizontals.

Formation Characteristics

The key to successful treatment design is to analyze formation characteristics, including

the rock that is present and that which is not (the pore spaces). A better understanding of

the formation characteristics leads to a higher probability for success. The most important

parameters are the rock composition and structure.

Rock Composition

Rock composition includes the mineralogical breakdown (the percentage of calcite,

dolomite, clays, etc.), the average HCl solubility in each interval, and the minerals that

could cause problems. Reservoir engineers think of rock structure as the permeability and

porosity profile. From a geological perspective, rock structure is better described by the

following terms: microcrystalline, oolitic, vuggy, fractured, chalk, etc.

Rock Structure

P e r m e a b i l i t y v s . P o r o s it y

Understanding rock structure is more important in carbonate treatment design than it is in

sandstone design because the correlation between permeability and porosity in sandstone

formations generally has a reasonable relationship. Often, a reasonable relationship is not

the case in carbonate formations. A North Sea Ekofisk chalk might have porosity as high

as 40%, yet the effective permeability may be less than 1 Md. A southern Mississippi

Smackover dolomite might have less than 5% porosity, yet the permeability may be as

high as 20 Md.

S o l u b i l i t y

Another example of the importance of rock structure is related to solubility. A San Andres

dolomite might have an overall solubility of 80% with the insoluble portion of the rock


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being anhydrite localized in patches or nodules. In this case, the presence of insoluble

material does not significantly impact treatment design. In the North Sea, the Barremian

limestone may also have an overall solubility of 80%, yet the presence of 20% quartz and

clay distributed throughout the matrix of the rock would require a modified design.

F o r m a t i o n D e s cr i p t i o n

Even the formation description may be misleading. Figures 5A and 5B show SEM

photomicrographs of two formations described as "chalky": the Ekofisk in the Norwegian

sector of the North Sea and the Mishrif , located offshore near Dubai. Both formations are

primarily calcite with an HCl solubility of about 95% and a Young's modulus of about 10 6

psi. Under low magnification (300× to 600×), these two formations appear to be similar.

On a microscopic scale, however, the rock structures are very different. The Ekofisk

sample at 3000× magnification has ultrahigh porosity and still contains many fossil

remnants. Little or no cementation is present. The Mishrif sample at 1500× magnificationis much denser as a result of a high degree of recrystallization. These significantly

different pore structures require different treatment techniques.

Figure 5A: North Sea Ekofisk at 3000x/600x


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Figure 5B: Arabian Gulf Mishrif at 1500x/300x


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Acid Reaction in Porous Media

Over the past decade, several research groups 10-22 have studied the flow and reaction of

acid in carbonate formations. Although the experimental techniques and numerical models

advocated by each group may vary, all agree that three distinct dissolution regimes exist:

compact dissolution, uniform dissolution, and wormhole formation.

Compact Dissolution

Compact dissolution occurs when the acid spends on the face of the formation. In this

case, the live acid penetration is limited to within centimeters of the wellbore.

Uniform Dissolution

Uniform dissolution occurs when the acid reacts under the laws of fluid flow through

porous media. In this case, the live acid penetration will be, at most, equal to the

volumetric penetration of the injected acid.


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Wormhole Formation

Wormholes form when the invasion or flow of the reactive fluid through the porous media

is nonuniform. Figure 6 shows the "skeleton" of a wormhole, which is an epoxy casting of

the dissolved pore space or wormhole formed in a carbonate core as a result of matrix

acidization. The original core was the size of the gray area. Acid was injected under

conditions to achieve wormholing. After the wormhole was filled with epoxy, the

remaining core was dissolved, leaving behind only the wormhole skeleton.

Wormholing is the preferred dissolution process for matrix-acidizing carbonate formations

because it efficiently forms highly conductive channels. Large permeability increases can

be achieved with fractional pore volumes of acid, so the live acid penetration can be

significantly greater than the average radial fill around a wellbore, resulting in a greater

reduction in skin factor for an equivalent volume of acid pumped.

Wormhole Efficiency

Experimental research has shown that the process of wormholing depends mainly on

three parameters: 1) surface reaction rate, 2) acid diffusion rate, and 3) acid injection

rate.

Surface Reaction Rate

The surface reaction rate determines how fast acid reacts with carbonates at the rock

surface. This rate is a function of the rock properties (composition and crystallinity).

Acid Diffusion Rate

The acid diffusion rate indicates how fast acid is transported from the bulk of the fluid to

the rock surface. The diffusion rate is a function of the acid system. Both of these

parameters are also a function of temperature. Either the surface rate or the diffusion rate

may control the overall acid spending rate, though both are always in balance with each

other. Wormholes form when the overall acid spending rate is diffusion-limited, which

results from a high surface reaction rate or a low diffusion rate.

Under conditions that do not inherently favor wormhole formation, increasing the acid

injection rate can allow wormholes to initiate and grow. More correctly, increasing the

fluid velocity allows live acid to be transported deeper into the formation. In laboratory

core flow tests, an optimum injection rate can be determined. This rate will vary according

to the sample configuration, test temperature, properties of the rock, and acid system

injected. For any given set of conditions, a critical velocity exists. Injection rates below


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this velocity will result in compact dissolution; injection rates greater than this velocity will

result in wormholes.

For example, at 175°F, with a 99.5% pure limestone under linear flow conditions, the

critical velocity for wormhole formation is 1.43 cm/s for plain 15% HCl and 0.29 cm/s for

emulsified 15% HCl.23 The absolute magnitude of the critical velocities is not as significant

as the fact that emulsified acid is five times less reactive than plain acid. Therefore, the

choice of fluid system can optimize matrix acidizing treatments. Retarded acid systems

can offset pump rate limitations imposed by low permeability, high pressures, or

equipment constraints.

Figure 6: Wormhole Formed by Acid Reaction in Carbonate Rock


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Completion methods can also affect wormhole efficiency. Table 3 compares a cased and

perforated completion to an openhole completion. In both cases, an acid injection rate of

2 bbl/min is assumed, and the total interval length is 100 ft of a 20% porosity, high-

reactivity carbonate. The cased-hole completion has 0.25 in. perforations at 1 shot/ft for a

total of 100 perforations. The openhole completion has an 8-in. diameter. These

parameters translate to a fluid velocity at the wellbore of 828 cm/s in the cased/

perforated completion and 0.13 cm/s in the openhole completion.

Guidelines for wormhole formation are given in Buijse and Van Domelen's paper.23 If the

entire interval uniformly accepts injected acid, wormholes will form in the perforated

completion, regardless of the acid system selected. In the openhole completion, however,

compact dissolution will occur with plain HCl because the fluid velocity is below the critical

velocity for wormhole formation. As a consequence, only part of the openhole interval will

accept acid under wormholing conditions, resulting in poor zonal coverage. A retarded

acid system, such as emulsified acid, would favor wormhole generation across the entire

openhole interval.

Table 3: Effect of Well Completion on Wormhole Efficiency

Fluid Selection

Fluid selection for any acidizing treatment should begin with a review of the formation

characteristics: rock composition, structure, permeability, porosity, and strength. The

properties of the reservoir fluids are the next variables to be considered. Bottomhole

temperature, pressure, and any limitations on injection rates must always be evaluated.

Any or all of these parameters may influence the choice of a base acid or additive

package.


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Base Acids

Because it is cost effective and generally leaves no insoluble reaction products, HCl is the

most commonly used acid in carbonate stimulation operations. Formic and acetic acid are

also used, both as additives and as base acid systems. Formic acid (HCOOH) and acetic

acid (CH3

COOH) are weakly ionized, slow-reacting organic acids. For field use, acetic acid

solutions are normally diluted to 15% or less. At concentrations above 17%, one of the

reaction products, calcium acetate, can precipitate because of its limited solubility.

Similarly, the concentration of formic acid is normally limited to 13% because of the

limited solubility of calcium formate. Organic acids are generally used in higher-

temperature applications or when the formation rock or reservoir fluid is incompatible with

HCl.

F o r m a t i o n Ro c k

High-porosity rocks such as chalks, tend to have large pore spaces connected by relatively

small pore throats. In this case, a weaker acid solution (10 to 15% HCl) is preferred,

because the acid only needs to widen the pore throat. Too much reaction and rock

dissolution can destroy the framework/matrix and cause rock failure. However, hard,

dense, low-porosity rocks such as dolomite, often have little intergranular porosity. The

framework grains must be dissolved (to some degree), which increases effective porosity

and thereby increases permeability. In this case, a stronger acid solution (20 to 28% HCl)

is preferred. If significant amounts of acid-insoluble fines exist, limiting the acid strength

can help limit the amount of fines released on a per-gallon basis. Many of these issues arediscussed in the Laboratory Testing of Carbonates best practices manual.

Re s e r v o i r F l u i d s

Reservoir fluids may also influence base acid selection. Generally, the concern is highest

in heavier crudes or any crude that displays sludging or severe emulsification properties.

Generally, strong acids cause more problems than weaker ones. Limiting the HCl

concentration to 20% is effective in many cases. Other times, the use of organic acids or

an appropriate additive package may be required to prevent acid sludge or emulsification.

B o t t o m h o l e Te m p e r a t u r e ( B H T )

The base acid should be selected by the process of elimination. If the BHT is very high,

corrosion concerns may be the primary design parameter. The inability to provide long-

term corrosion protection might limit the maximum HCl concentration possible. If the BHT

is extremely high, HCl may be precluded and organic acids might be preferred. If the


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formation has very low reactivity, as in the case of a cold dolomite, a more aggressive

acid (28% HCl) might be preferred.

Additives

Because hundreds of acid additives are available, the additive selection process can be

overwhelming. Two additives should be included in every carbonate stimulationtreatment: an acid corrosion inhibitor and a surfactant, which functions as either a

nonemulsifier, a surface-tension reducing agent, or both. While iron control is less a

concern in large stimulation treatments (because of the large volume of rock removed), it

is nevertheless important. The most appropriate iron-control package will be based on

temperature and whether the well is sweet or sour.

Carbonate 20/20 Acidizing Systems

Carbonate 20/20 acidizing systems help simplify the fluid selection process by providing

versatile acid systems that are "fit for purpose" for most conditions encountered in

carbonate formations throughout the world. Table 4 describes the available acid systems.

Corrosion inhibitor packages will vary based on BHT, required contact time, and tubular

metallurgy. Job designers should always conduct emulsion tests with a representative

crude sample to ensure that the appropriate surfactant loadings are used.

Table 4: Carbonate 20/20 Acidizing Systems


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Treatment Optimization with C-MAP

The Carbonate Matrix Acidizing Program (C-MAP) provides a systematic approach to

matrix acidizing treatment design for carbonate reservoirs. An analogous program, SS-

MAP has significantly increased the success rate of sandstone acidizing treatments. C-MAP

is not an expert system; it is a design tool that allows the user to evaluate the impact of

changes in a treatment program. C-MAP's required input data are readily available to the

average geologist, reservoir, production or completion engineer.

C-MAP is not intended to replace a comprehensive matrix acidizing simulator; it does

however, simplify an extremely complicated mathematical process. The result is a user-

friendly program that operates similarly to a spreadsheet program. C-MAP performs the

following steps in matrix acidizing treatment design on the following "sheets":

Customer and basic well information


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Formation or rock characteristics

Permeability, porosity, and skin profiles

Pressure and stress properties

Treatment schedule

Flow simulation, wormhole generation, skin reduction, and pressure response

Figure 7 shows the results of a C-MAP simulation for a horizontal, openhole well in a

formation with four layers. Table 5 contains layer information for the formation. C-MAP

can monitor as many as 10 layers and 25 fluid stages. Each stage may be a Carbonate

20/20 acid system, a nonreactive fluid, or an alternative user-selected acid system. For

this discussion, however, a very simple example treatment is sufficient. The treatment is

pumped at a constant 10 bbl/min and uses 250 bbl of nongelled 15% HCl. Four plots are

shown.

Table 5: Layer Information for C-MAP Example

Figure 7: C-MAP Flow-simulation Screen


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Fluid-Invasion Profile

The fluid-invasion profile (Figure 7), the most important profile, shows that most of the

acid was injected into Layers 2 and 3. The average fluid penetration radius was about 1.2

ft in these layers. Layers 1 and 4 took very little fluid; in fact, acid did not contact the

lower half of Layer 4.

This plot shows that this layered formation requires a diversion method for successful

stimulation. The "Diversion Advisor" in Stim 2001 is a probability-based expert system

that helps users select the most appropriate diversion techniques for given well

conditions. The Diversion of Matrix Acidizing Treatments Best Practices document provides

detailed guidelines on applying the chosen diversion technique.

The problem of acid penetration and optimum wormhole growth is directly linked to acid

placement. Figure 7 shows that wormholes were generated in Layers 2 and 3 (cross-

hatched area), but not in Layer 1 (even though some acid did enter Layer 1). Low-

permeability or high-skin sections tend to accept little acid, so the velocity of the injected

acid in such sections may be too low for wormholes to form. Therefore, all acid will spend

on the wellbore wall, with little or no live acid penetrating deeper into the formation. This


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compact dissolution phenomenon does not significantly reduce skin.

Skin plots appear to the right of the fluid invasion plot in Figure 7. The top plot shows the

skin profile along the hole; the bottom plot shows total skin as a function of treatment

time. In Layer 1, the skin remains positive, hardly varying from the original skin value.

Good skin reduction is achieved in Layers 2 and 3, although it could be improved; the skin

values vary from a slightly positive value down to only about -1. As with Layer 1, little or

no skin reduction was achieved in Layer 4.

The danger of evaluating a matrix acidizing treatment based on total skin alone is

demonstrated by the lower skin plot. In this case, the treatment appears to be optimized,

since the total skin value reaches 0 just as the last acid is injected. If the individual zones

were tested, or a PLT were run, it would be apparent that only Layers 2 and 3 contribute

significantly to production.

Other Scenarios

C-MAP allows users to evaluate an infinite number of scenarios using parameters such as

1) the use or retarded acid or viscous, nonreactive fluid, 2) pump rate, 3) wellhead or

horsepower limitations, or 4) original permeability.

C-MAP requires only input data that are readily available. Default parameters for fluid

rheology, friction pressures, formation reactivity, critical wormhole velocities, etc. are

embedded into the code, allowing users to evaluate all potential treatment scenarios with

very little time or effort. The combination of C-MAP and the Carbonate 20/20 acid system

allows the more effective design of carbonate matrix acidizing treatments.

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5. Allen, T.O. And Roberts, A.P.: Production Operations, Vol. 2 (Oil & Gas Consultants

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Experiment for Hydrochloric Acid Interaction with Limestones," paper SPE 27401presented at the 1994 International Symposium on Formation Damage Control,

Lafayette, Feb. 7-10.

18. Mostofizadeh, B. and Economides, M.J.: "Optimum Injection Rate From RadialAcidizing Experiments," paper SPE 28547 presented at the 1994 Annual Technical

Conference and Exhibition, New Orleans, Sept. 25-28.

19. Bazin, B., Roquw, C., and Bouteca, M.: "A Laboratory Evaluation of AcidPropagation in Relation to Acid Fracturing: Results and Interpretation," paper SPE

30085 presented at the 1995 European Formation Damage Conference, TheHague, May 15-16.

20. Brazin, B, et al .: "Improvement in the Characterization of the Acid Wormholing by

In-Situ X-Ray CT Visualizations", paper SPE 31073 to be presented at the 1996International Symposium on Formation Damage Control, Lafayette, Feb. 14-15.


23/23

21. Brazin, et al.: "Acid Filtration in Dynamic Conditions to Mimic Fluid Loss in AcidFracturing," paper SPE 38168 presented at the 1997 European Formation Damage

Conference, The Hague, Jun. 2-3.

22. Buijse, M.A.: "Understanding Wormholing Mechanisms Can Improve Acid

Treatments in Carbonate Formations," paper SPE 38166 presented at the 1997European Formation Damage Conference, The Hague, Jun. 2-3.

23. Buijse, MA and Van Domelen, M.S.: "Novel Application of Emulsified Acids to

Matrix Stimulation of Heterogeneous Formations," paper SPE 39583 presented atthe 1998

24. International Symposium on Formation Damage Control, Lafayette, Feb. 18-19.

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10/2/2008

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