SPE 168167

Experience of Carbonate Acidizing in the Challenging Environment of the Volga-Urals Region of Russia Rifat Kayumov, Andrey Konchenko, Alexey Bairamov, Artem Klyubin, and Olesya Levanyuk, Schlumberger; Andrey Chikin, Vladislav Firsov, and Evgeniy Nikulshin, Rosneft

Copyright 2014, Society of Petroleum Engineers This paper was prepared for presentation at the SPE International Symposium and Exhibition on Formation Damage Control held in Lafayette, Louisiana, USA, 26–28 February 2014. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract The Volga-Urals basin is one of the largest oil-producing regions in Russia. Orenburg region is essential part of Volga-Urals

basin and it represents most of the challenges encountered in the other parts of the basin. More than half the wells produce

exclusively from carbonate formations and require periodic acidizing treatments to maintain economic production. Carbonate

stimulation treatments are usually based on pumping of hydrochloric acid into the formation with use of special diverters to

maximize zone coverage by acid treatment. Some of the formation properties in Volga-Urals basin create additional

challenges for successful acidizing treatments, including significant reservoir pressure depletion, high water cut, formation

heterogeneity with high- and low-permeability strikes, low reservoir temperature, crude with tendency for emulsion and

sludge creation, and enormous thief zones created by previous acidizing treatments. In many cases, uncertainties in the

formation properties make the stimulation more complex.

Carbonate stimulation practices in the Orenburg region have continuously improved during the last 6 years. First,

degradable balls and polymer self-diverting acid were introduced to improve zone coverage. Later, viscoelastic self-diverting

acid was added to eliminate damage associated with the polymer, and a viscoelastic selective diverter was used to minimize

the probability of an increase in water cut after the treatment. Finally, foam was placed as a diversion agent, with and without

coiled tubing (CT), to account for reservoir pressure depletion and help in post-acidizing flowback. Many lessons were

learned, resulting in recommendations for use of various technologies at different reservoir and wellbore conditions.

In addition to the recommendations for technologies, a quality assurance and quality control (QAQC) standard was

developed and implemented for acidizing treatments. Moreover, laboratory work such as core flow testing and proppant

embedment tests has been undertaken to clarify post-treatment aspects.

Most fields in the Orenburg region are old, which implies that quality of well candidates became worse from year to

year. However, with continuous improvement in stimulation practices and rigorous quality control we manage to maintain

production at economic level and even increase work scope compared with previous years. This paper presents the

experience gained during the 6-year of acidizing treatments in Orenburg region with lessons learned, and best practices

adopted.

Introduction The Volga-Urals basin is one of the oldest and largest oil-producing regions in Russia. The first oil on the western edge of the

Ural Mountains was discovered in 1929, and major development started in the late 1930s. By 1977, decades of climbing

production from Volga-Urals basin were over and a sharp decline had begun. The decline occurred mainly because most of

the resources are concentrated in a few extremely large fields, and the rest are divided among a very large number of small

fields. All giant fields were discovered before 1960 and had become mature by late 1970; the newly explored fields were too

small to reverse the basin’s production decline. Today, the Volga-Urals basin is no longer Russia’s premier producer, but the

basin is still responsible for nearly a quarter of Russian oil supply (Grace 2005).

The Orenburg region, an important component of the Volga-Urals basin, is located near other oil- and gas-producing

provinces: Bashkortostan, Tatarstan, Samara region, and north Kazakhstan. The geological structure of the Volga-Urals basin

is very complex. The basin formed over the course of more than 200 million years. The stratigraphy within the Orenburg

2 SPE 168167

region (Table 1) reflects three major sedimentary cycles of deposition. Hydrocarbons have been found in formations from all

the geological periods. The distribution of recoverable reserves is also shown in Table 1 (ONAKO 1997).

Fig. 1. Fields in the western part of the Orenburg region

There are more than 100 oil fields scattered in the western part of the Orenburg region (Fig. 1). Table 2 shows

distribution of oil reserves by accumulation size (ONAKO 1997). Distribution shows that 41% of recoverable reserves and

73% of all reservoirs are found in small accumulations with oil reserves from 1 to 30 million tons. Many accumulations

(26.3%) have reserves less than 1 million tons of oil, but they contain only 4.7% of the total recoverable reserves.

Most oil fields in the region belong to the Rosneft oil company, and this paper focuses on these fields. As can be seen

from Table 1, many of the formations are carbonates, especially those of Permian and Carboniferous age. About 60% of

recoverable reserves are in carbonate formations and 75% of wells produce completely or partially from carbonates (Fig. 2).

A total of 98 oil fields are producing from carbonate formations, and their distribution by well count is shown on Fig. 3.

Apart from a few big oil fields, the vast majority of the fields are small: 82 out of 98 fields have fewer than 20 wells

producing from carbonate formations.

TABLE 1. A STATIGRAPHIC CROSS SECTION OF ORENBURG REGION.

Geological period

Subperiod Formation

index Lithology

Recoverable reserves,

% of the total

Permian Upper

KS Carbonate

24.1 U1 Carbonate

U2 Carbonate

Lower PI - PVII Carbonate

Carboniferous

Upper G Carbonate

40.8

Middle

Mch Carbonate

Pd Carbonate

Kr Carbonate

A0 Carbonate

A1 - A3 Sandstone

A4 - A6 Carbonate

Lower

Sp Carbonate

O1 - O6 Carbonate

T1 Carbonate

B0 Carbonate

B1 - B2 Sandstone

CII - CVI Sandstone

T1 - T3 Carbonate

Devonian

Upper

Zl Carbonate

35.1

DfI - DfV Carbonate

Dfr1 - Dfr4 Carbonate

Dkt1 - Dkt3 Sandstone

Dkn Sandstone

Dkj Carbonate

D0 - D1 Sandstone

Middle D2 - D4 Sandstone

D5 - D6 Carbonate

Lower D7 Sandstone

TABLE 2. DISTRIBUTION OF OIL RESERVES IN ORENBURG REGION BY ACCUMULATION SIZE.

Oil reserves, millions of

tons

Amount of reservoirs, %

of total

Recoverable reserves, % of

total

< 1 26.3 4.7

1 - 5 38.1 21.8

5 - 10 14.2 14.5

10 - 30 21.1 40.1

> 30 0.3 18.9

SPE 168167 3

Fig. 2. Well count by formation type. Fig. 3. Well count for oil fields producing from carbonate formations.

Acidizing is a well-established method for

stimulation of carbonate reservoirs, and some

important aspects of these treatments are

described in the next section. Some of the

formation properties in the Orenburg region create

additional challenges for successful acidizing

treatments:

• Reservoir pressure depletion. Most of the

carbonate formations have been in development

for many decades and water injection was

established for formation pressure maintenance. It

keeps the average reservoir pressure from sharp

depletion but cannot completely stop this process.

Fig. 4 shows the average reservoir pressure is 60

to 75% of the initial pressure for most of the

carbonate formations. Fig. 4 also shows the

distribution of formations by total well count and

number of acidizing treatments for reference.

• High water production. In the Volga-Urals

region, oil-saturated layers are usually located near

water-saturated zones or have active aquifers. It is

not surprising that after decades of production most

of the formations produce at high water cuts. Fig. 5

shows that except for the deep Devonian formations

(D5-D6), average water cut is significantly above

50% and most of the produced fluid is water. The

water sources may be different (from injector wells,

rise of water/oil contact, crossflow behind casing,

natural fissures, unsuccessful stimulation with

breakdown to adjacent water layer, etc.) and are

usually not precisely known.

• Low reservoir temperature. Fig. 6 shows

that most carbonate formations in the region have

stable bottomhole static temperatures (BHST) from

30° to 60°C. The only formations with BHST above

60°C are Devonian, but the number of wells

producing from Devonian formations is much lower

than the number producing from Carboniferous

(Fig. 4 and Table 1).

1271

54%580

25%

489

21%

Carbonates

Sandstone

Both

294

252

163

88727054

4943

4139

3333

2923

22

455

Total of 98 fields

Bobrovskoe

Sorochinsko-Nikolskoe

Pokrovskoe

Samodurovskoe

Pronkinskoe

Ibryaevskoe

Krasnoyarskoe

Sultano-Zaglyadinskoe

Rodinskoe

Dolgovskoe

Kodyakovskoe

Tananykskoe

Tarhanskoe

Kurmanaevskoe

Garshinskoe

Tokskoe

Others (<20 wells)

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

A0 A4 - A6 O1 - O6 B0 T1 - T3 Zl Df1 - Df4 D5 - D6

Wells count, % to total

Acidizing treatments, % to total

Pres (current) / Pres (initial)

0%

20%

40%

60%

80%

100%

0.0

20.0

40.0

60.0

80.0

100.0

120.0

A0 A4 - A6 O1 - O6 B0 T1 - T3 Zl Df1 -

Df4

D5 - D6

Ave

rag

e w

ate

r cu

t, %

Av

era

ge p

rod

uct

ion

, m

3/d

ay

Average Qw, m3/day Average Qoil, m3/day Average WC

Fig. 4. Formation pressure depletion and distribution of wells and treatments by carbonate formation.

Fig. 5. Average production and water cut for carbonate formations.

4 SPE 168167

• Formation heterogeneity. The carbonate

formations in Orenburg region are very laminated.

The productive sublayers in one formation may vary

from 3 to 30 and even more. These sublayers are

separated by tight and impermeable streaks with

comparable height. An example of such a formation is

presented in Fig. 7. The presence of water-saturated

zones near the target intervals are highlighted by blue

ovals.

• Crude with tendency for emulsion and sludge

creation. In general, the crude in the Volga-Urals

region is heavy and viscous. Fig. 8 showed API

gravity and bottomhole (BH) viscosity values from

wells producing from carbonate formations in the

Orenburg region. Almost all wells are producing

black oil with 70% producing hydrocarbon at API

values less than 40. The same chart also shows the BH

viscosity is more than 3 cp for half the wells. It is well

known that viscous black oil has a tendency to create

emulsions and sludge with acids. Fig. 9a and 9b

represent bad and good results of compatibility tests

between crude and 15% HCl for one of the wells in

Orenburg region: the left picture shows sludge creation

as a result of mixing crude sample with acid. To achieve

good compatibility results, some special additives have

to be used. Fig. 10 showed that average concentration

for such additives in Orenburg region is very high and

even higher than the recommended maximum values for

each additive. Such high concentrations of additives

were accepted to minimize the risk of formation

damage during the acidizing treatments.

0

2

4

6

8

10

12

Non-emulsifier, liquid Anti-sludge, liquid Iron control agent, dry

Ad

dit

ive

co

nce

ntr

ati

on

, lt

/m

3 o

r k

g/

m3

Recommended max. concentration

Actual average concentration

0

3

6

9

12

15

20

25

30

35

40

45

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

BH

Oil

Vis

cosi

ty,

cP

Oil

AP

I g

rav

ity

Cumulative well count

Oil API gravity

BH Oil Viscosity

0%

5%

10%

15%

20%

25%

30%

35%

40%

< 30 30 - 40 40 - 50 50 - 60 60 - 70 70 - 80 80 - 90 90 - 100 > 100

We

lls c

ou

nt

BHST, deg.C

Fig. 6. Distribution of wells by stabilized reservoir temperature (only

carbonate formations)

Fig. 7. Typical log data for Zl formation in Orenburg region

Fig. 8. Oil API gravity and bottomhole viscosity for wells producing from carbonate formations

a) b)

Fig. 9. Bad (a) and good (b) results of compatibility test

Fig. 10. Comparison of recommended and actual average additives concentration

SPE 168167 5

0

5

10

15

20

25

30

2007 2008 2009 2010 2011 2012

Job

s co

un

t

5th treatment

4th treatment

3rd treatment

2nd treatment

• Multiple acidizing treatments. Each

acidizing treatment dissolves a significant amount of

formation rock, thus increasing the contact area with

the formation and potentially creating thief zones

that can consume most of the stimulation fluid

during subsequent treatments. Thus, the

effectiveness of the each subsequent treatment will

usually decrease. Fig. 11 shows the number of

repeated acidizing treatments from 2007 to 2012. It

is clear that the number of re-treated wells is

continuously increasing with time and it is logical

that this trend will continue.

• Uncertainties in formation properties.

Carbonate formations are rarely uniform, and

formation properties can vary from one well to

another even in the same field. As noted previously,

the Orenburg region is characterized by large

numbers of small fields with a variety of formation properties. Well test operations for each field are not

economically feasible, and sometimes impossible because many wells have commingled production from multiple

formations. Additionally, production logging is not performed on every well before and after treatments. This makes

achieving successful acidizing treatments even more complex.

General Discussion of Carbonate Acidizing Acidizing of carbonate formations is one of the oldest stimulation techniques. First reported cases of carbonate acidizing are

dated 1895. The Standard Oil Company used concentrated hydrochloric acid to stimulate oil wells producing from carbonate

formations in Lima, Ohio, USA. Acid stimulation on a commercial basis started later in 1929 with collaboration of Pure Oil

Company and Dow Chemical Company to treat wells in Michigan, USA; the collaboration resulted in new types of organic

tubing corrosion inhibitors, which had great success and increased the demand for well stimulation (Williams et al. 1979).

Acids dissolve formation minerals and other foreign materials, such as drilling mud and scale precipitates. The extent to

which the dissolution will increase well productivity depends on a number of factors, including the type of treatment chosen.

All treatments can be divided into three main types: acid washing, matrix acidizing, and acid fracturing.

• Acid washing is primarily used to remove acid-soluble scales in the wellbore or to open perforations. It is

usually performed by spotting relatively small quantities of acid at a specific location in the wellbore. The acid

can be circulated across the perforations and formation face to accelerate the dissolution process.

• Matrix acidizing is the injection of acid into the formation pore spaces at a pressure below that at which a

fracture can be opened. The primary purpose is to remove or bypass damage that is due to scale, mud, clay, or

hydrocarbon deposits and to restore natural formation permeability. Hydrochloric acid is commonly used as

main treating fluid, but if high BHST do not allow effective protection of the tubing from corrosion, other acid

systems can be used (acetic acid, formic acid, citric acid, non-acid chelate systems). Matrix acidizing is often

performed where acid fracturing cannot be used because of the risk of fracture breakthrough into unwanted

intervals (i.e. gas or water bearing sublayers).

• Acid fracturing is the injection of acid into the formation at a pressure high enough to overcome tensile and

compressive stresses of the rock and fracture the formation or open and extend existing fractures. Continued

fluid injection increases the fracture length and width. Acid injected into the fracture creates a flow channel that

remains open when the well is placed on production. Although acid fracturing can improve performance in

terms of post-treatment production, its application is usually limited to formations without a significant risk of

fracture breakthrough into adjacent water- or gas-bearing formations. Acid fracturing deals with much more

complex physical and chemical phenomena than matrix stimulation. The first numerical models of acid

fracturing were reported in work by Nierode et al. (1972). Fracture geometry, fluid-loss rate, injection rate, acid

penetration distance, temperature, formation type, acid type, and other parameters must be evaluated to design

acid fracturing treatments and predict post-treatment well performance.

Use of straight acid can cause a number of problems for the well. Pumping acid into the well potentially can corrode

steel tubing and casing; releases fines that can plug formation; forms insoluble inorganic precipitates; forms emulsions; or

creates insoluble sludge. In most cases acids are modified with additives that used to prevent these problems. Such additives

can include corrosion inhibitors, surfactants and suspending agents, iron control agents and many others. Surfactants are used

in acidizing to break undesirable emulsions, reduce surface and/or interfacial tension, alter wettability, speed cleanup,

disperse additives, and prevent sludge formation. Also, they can be used a a foaming agents.

Diverting agents are playing significant role in post-treatment production results after the matrix acidizing. Acid will

usually follow the path of least resistance, usually lesser damaged or higher permeability intervals. All diverting agents are

Fig. 11. Repeated acidizing treatments

6 SPE 168167

designed to equalize the flow so that zones of differing permeability can be treated. Mechanical diverters rely on temporary

physical plugging of intervals with the most injectivity; chemical diverters rely on changing the viscosity of the treating fluid.

When acid is spent, chemical diverters added to the fluid generate temporary viscous pills inside the treated formation, thus

redirecting fluid flow to other parts of the formation. Examples of both types of diverters are provided in another section of

this paper.

Quality Assurance and Quality Control Standard for Acid Stimulation A rigid and comprehensive QAQC standard for acid stimulation was established by the operating company in the Orenburg

region to enable the service companies to perform at a higher service delivery level. This document contains information on

safety and operational requirements as well as stimulation fluid testing procedures.

Acidizing fluids are very dangerous and exposure can be fatal if inhaled or ingested; injury to eyes can be rapid and

severe. During matrix acidizing and especially acid fracturing, acids are pumped at high surface pressures. To minimize the

risk of injury during handling of reactive fluids and high-pressure pumping operations, the QAQC standard contains sections

on safety and operational requirements.

Because improper fluid formulation is one of the main reasons for failed stimulation treatments, the standard describes

the set of obligatory tests procedures for each type of fluids in both district and field laboratories. The requirements to

laboratory equipment are also specified.

Special attention is paid to iron content in the treating fluids. If significant amounts of ferric iron (Fe3+

) are dissolved in

acid, it can precipitate in the formation and create damage. Moreover, dissolved iron facilitates creation of sludge and strong

emulsions between formation fluid and acid. Since hydrocarbons in Orenburg region are viscous, high concentrations of

additives are required to provide good compatibility between acid and formation fluid. Iron control became absolutely critical

for treatment success. To eliminate iron consumption from surface, the standard prohibits injection of any acids with more

than 100 ppm of ferric iron. To minimize the negative influence of iron from tubular to formation, pickling procedures are

described. Tubing pickle acid should successfully pass the compatibility tests with formation fluid with addition of 5,000

ppm of ferric iron. The assumption is that all tubing pickle acid will be recovered at surface and will not be injected into the

formation. Volume of tubing pickle should be not less than 2 m3. If a full tubing pickling procedure is performed and the

returned surface acid is measured to contain less than 1,000 ppm of iron, the remaining iron control agents in the acid volume

can be reduced to 1,000 ppm control. Since carbonate reservoirs in Orenburg region are depleted, it is not usually possible to

circulate pickle acid out of the wellbore. If a tubing pickling procedure is not possible or not considered, the first 7 m3 of

acid pumped must contain the amount of iron control agents that will control 5,000 ppm of ferric iron. The remainder of all

acid pumped for that treatment must be able to control a minimum of 2,000 ppm of iron. When acid treatments are performed

with volumes more than 7 m3, the acid blends designed to control 5,000 and 2,000 ppm of Fe

+3 are subjected to the full suite

of compatibility tests.

Obligatory tests for any acid-based systems described in standard:

• Acid stability testing is designed to check acid stability with all required additives at room and expected bottomhole

temperatures (BHT), with and without presence of ferric iron. If any separation, clouding change, or precipitation is

seen after 30 min on any of the test bottles, the acid will be rejected from pumping. Additionally, all bottles will be

poured through the filter paper to verify that there are no undesirable precipitates.

• Emulsion break test is conducted to determine whether proposed acid formulation can effectively destroy emulsion

between treating and formation fluids. All tests are conducted with presence of ferric iron in acid: 5,000 ppm for

pickling acid, 2,000 ppm for the rest of the acid if pickling acid will be injected into formation, and 1,000 ppm for

the rest of the acid if pickling acid will be circulated out. Four different bottles are mixed and placed into water bath

at BHT for emulsion break test: 25% fresh acid + 75% crude oil; 50% fresh acid + 50% crude oil; 75% fresh acid +

25% crude oil; 50% spent acid + 50% crude oil. Acid in all bottles should contain all additives. The acid will be

rejected if the crude oil and acid phases do not separate completely in all bottles during 30 min.

• Sludge test is performed to check tendency of sludge creation. The content of the four bottles remaining after

completing the emulsion break test should be poured through the filter paper. Note that the bottle with spent acid

should be filtered after 4 h in water bath at BHT; the other three bottles can be filtered after 30 min in water bath.

This is because spent acid stays in the formation after the treatment for a much longer time than fresh acid. The acid

will be rejected if the filter paper catches sludge or precipitate, or if it fails to pass all the liquid in a reasonable

period of time.

• Corrosion rate test is performed to design adequate concentration of corrosion inhibitor. The steel coupon is placed

in the bottle with acid contained all additives at BHT for 12 h. The weight loss should be less than 0.009765 g/cm2

for BHT < 93°C and less than 0.024412 g/cm2 for higher BHTs. If weight loss is greater than this, the test will be

considered a failure, corrosion inhibitor must be changed or concentration increased, and then the test repeated until

the limits are achieved. It is expected that a pitting index of 5 or less will be observed after a corrosion rate test.

All these tests should be performed in a district lab first and then repeated in the field with mixed treating fluids just

before pumping. The exemption is the corrosion rate test, which should be performed at the district lab only.

Additionally, QAQC standard has data recording requirements set the minimum list of parameters that must be recorded

SPE 168167 7

and provided to operating company after each treatment: main line pressure, annulus pressure, flowrate. Recording of other

parameters (temperature, density, etc.) of pumped fluids or stages is not mandatory but welcome. Turbine or magnetic

flowmeters are preferred tools for flow rate measurements. Pump stroke counters can be used only as a backup rate device.

General Overview of Carbonate Acidizing Treatments in Orenburg Region Before 2007 only simple carbonate acidizing treatments were performed. These consisted of injecting a small volume of

inhibited HCl at low pump rate and surface pressure and were usually performed during workover operations with little

supervision and without digital recording of treatment parameters. After 2007 the situation drastically changed, and the

QAQC standard was introduced. Since that moment, all acidizing treatments in the region were split into two groups: small-

volume treatments with simplified QAQC requirements (but still much stronger than before) and large-volume treatments in

full compliance with QAQC standard. The small treatments were usually performed by local service companies with some

attention to treating fluid compatibility but little to engineering (no diversion, generalized design approach irrespective to

well conditions). This paper focuses only on the large-volume treatments that included engineering support on design,

execution, and evaluation stages.

At the initial stage of an acidizing project very little information on formation properties has been available. The

following techniques have been successful in obtaining the rest of the necessary parameters:

• Nodal analysis has been used to validate each candidate well for stimulation. Reservoir net height is usually well

known from log data, but formation permeability and skin values are unknown. Any kind of well test operation is an

uncommon procedure in the region due to many reasons like commingled production from multiple formations or

completion restrictions. Therefore, average reservoir permeability for each well is estimated by analyzing the

production regime with assumption of zero skin. The planned post-treatment skin is obtained from carbonate

acidizing simulation software. Thus, post-treatment production prediction can be made with nodal analysis and an

economic study can be performed to validate whether the well was an appropriate candidate for stimulation. After

accumulating experience in a particular field, the reservoir permeability values can be derived from actual post-

treatment production results on offset wells. But such assumption is rarely applicable for the Volga-Urals region

because too many small oil fields (Fig. 1 and Fig. 3) are considered as candidates for stimulation, and there is

limited acidizing experience in each particular field.

• At least one short step rate test (SRT) injection has been performed on each field. The aim was to obtain reliable

fracture gradient (FG) values for each field. Later the FG values were used to define maximum allowable pump rate

for matrix treatments and to obtain fracture geometries for acid fracturing treatments. It is not desirable to perform a

SRT before each particular treatment; this test implies the creation of fracture in the formation and most formations

in the region have water-bearing layers near the target zones. Rather, one FG value was obtained for a particular

reservoir in the field, and later this value was used for all other wells in this area without additional SRT injections.

Our experience showed that average FG for carbonate formations in Orenburg region varies from 16 to 19 kPa/m.

• As already noted, matrix acidizing treatments are performed at bottomhole pressures (BHP) less than the fracture

closure pressure (derived from FG in previous step) to eliminate the risk of formation breakdown with subsequent

losses of treating fluids and potential connection of pay zone with adjacent water-saturated layers. But BHP cannot

be easily measured during the treatment and only surface pressure is registered in real time. To recalculate BHP

from surface pressure, friction losses in the tubular for each treating fluid should be known. In the Orenburg region

only two tubing sizes are used for acidizing treatments (2.5-in. OD and 3.5-in OD). At the beginning of the project,

memory BHP gauges were often run to obtain reliable friction data for each tubing size. Later, these values were

used for all treatments to recalculate BHP with good confidence.

• Special software was used to design total

volumes and pump schedules for matrix acidizing

and acid fracturing treatments. The following

goals were set for matrix acidizing design: skin

value less than –2, wormholes penetration of more

than 0.8 m, and uniform zone coverage during the

treatment. The following goal was set for acid

fracturing design: etched fracture length not less

than 20 m. If a water zone exists in proximity to

pay zone, only matrix acidizing is applicable. The

pump rate for matrix acidizing should be as high

as possible but without overcoming FG. Acid

fracturing should be pumped at maximum possible

rate with respect to wellhead and completion

pressure limitations.

Fig. 12 shows the distribution of acidizing

treatments from 2007 to 2012. Most of the Fig. 12. Distribution of acidizing treatments by type of treatment

0

20

40

60

80

100

120

140

2007 2008 2009 2010 2011 2012

Job

s C

ou

nt

CT Matrix Acidizing

Acid Fracturing

Bullhead Matrix Acidizing

8 SPE 168167

performed treatments are bullhead

matrix acidizing. CT placement is

rarely performed because of pump rate

limitations, but it has some unique

benefits that are described in another

section of this paper. The number of

acid fracturing treatments decreased

during the last 2 years because there

were few good candidates: most wells

with no water zone nearby were

already fractured and the rest are

unsuitable for this technology.

Generally speaking, the quality of

candidates is decreasing with time. All

good candidates were treated in the

first years of the project, and, except

for newly drilled wells (mostly to

Devonian formations D5-6; see Fig. 4

and Fig. 5), only challenging wells are

available for stimulation. The

challenges are different: high water

cut, significant depletion, large thief

zones resulting from repeated acidizing, low-

temperature fissured dolomites, several perforated

formations, and many others. To account for these

challenges, different technologies must be applied.

Fig. 13 shows the distribution of performed

treatments by technologies. The easy candidates at

the beginning were treated with the simple

technologies. But with time more advanced

technologies and their combinations had to be used

to achieve treatment goals. The following sections

describe in detail most of the technologies listed in

Fig. 13.

Though it is a very difficult to represent

treatment’s results on the single chart due to tens of

different oilfields with unique reservoir properties

that was treated in period between 2007 and 2012,

attempt was made and the result is presented on

fig. 14. Only wells with preacidizing production history (“old” wells) were used for this analysis. Bars show the average fluid

productivity index (PI) increase after the stimulation; light blue squares represent water cut before treatment, and dark blue

triangles show post-treatment water cut. Although the quality of candidates has become worse with years, use of suitable

technologies with an engineered approach for each well has kept the significant production incremental at a stable level with

a minor water cut increase. This result enables continuation of the acidizing project and even an increase in the number of

stimulation treatments on carbonate reservoirs from year to year (Fig. 12 and Fig. 13).

Evolution of Diversion Techniques Used in Orenburg Region Uniform zone coverage is the most important task for any carbonate acidizing treatment. Fig. 13 shows the technologies

implemented in this region; some were successful and others were cancelled after initial trials. Figs. 15 and 16 provide the

summary of these results for each technology for the most frequently stimulated fields in Orenburg area. Fig. 15 represents PI

increase that resulted from stimulation for the wells with preacidizing production history (“old” wells). The PI increase was

normalized to the largest value for each field, so the value of 1 on the chart represents the best average result achieved on

particular field. Fig. 16 represents post-acidizing PI for the wells without preacidizing production history (“new” wells),

usually newly drilled wells, sidetracks, or wells with a change in producing interval. The post-acidizing PI was also

normalized to the maximum value for each field. The black horizontal lines on Figs. 15 and 16 represent the average

normalized PI increase or post-acidizing PI values for each technology. The green dots show the total jobs count for each

technology on particular field and the red dots represent the number of unsuccessful jobs. The reasons for job failure can be

different, but the most common are water breakthrough and inability to unload the well from treating fluids because of low

reservoir pressure. The results presented in Figs. 15 and 16 are discussed in following sections of this paper with experience

gained from each technology.

Fig. 13. Distribution of acidizing treatments by technologies (PSDA: polymer-based

self-diverting acid; AF/GP: acid fracture with gelled pad; DBS: degradable ball

sealers; VSDA: viscoelastic self-diverting acid; VSD: viscoelastic selective diverter;

FD: foam diverter; AF/REA: acid fracture with retarded emulsified acid; REA:

retarded emulsified acid; FVSDA: foamed viscoelastic self-diverting acid)

Fig. 14. Average results of treatments performed on “old” wells

0%

5%

10%

15%

20%

25%

30%

35%

40%

0%

20%

40%

60%

80%

100%

120%

2007 2008 2009 2010 2011 2012

Ave

rage

wa

ter

cut

Ave

rag

e P

I in

cre

ase

PI increase Pre-acidizing WC Post-acidizing WC

0

20

40

60

80

100

120

140

2007 2008 2009 2010 2011 2012

Job

s C

ou

nt

FVSDA

FD+REA

FD+VSDA

AF/REA

VSD+PSDA

VSD+FD

VSD+VSDA

FD

VSD

VSDA

DBS + PSDA

AF/GP

PSDA

SPE 168167 9

Fig. 15. Average results of acidizing treatments performed on old wells for the most frequently stimulated oil fields

Fig. 16. Average results of acidizing treatments performed on new wells for the most frequently stimulated oil fields

Degradable ball sealers Soluble ball sealers are used as a means of selectively sealing perforations and diverting stimulation fluids to other

sections of the formation. They are introduced into the stimulation fluid between the pump and wellhead through special ball

injecting device and are carried to the perforations by the treating fluid, sealing the perforations in a sequence related to the

fluid acceptance. The perforations taking the most fluid are sealed first, thereby diverting fluid into the perforations taking

less fluid. Once in place, the balls are held there by differential pressure. The minimum pump rate limitation exists to pump

the balls. The balls dissolve over time when in contact with live acid or treatment brine at BHT but are insoluble in

hydrocarbons, including crude oils. Ball sealers dissolve within 2 to 6 h, depending on the acid strength and temperature.

At the start of Orenburg acidizing project, four matrix acidizing treatments were designed to use the combination of

degradable ball sealers and polymer self-diverting acid. Ball sealers were pumped as the first diverter stage after some

volume of acid. The idea was to block the potential thief zones so that the next alternating stages of acid and chemical

diverter would treat the rest of the interval. Only one well showed good surface pressure response (sharp increase of 30 atm)

when the balls hit the perforations, but even this pressure gain lasted only a few minutes before declining quickly to the initial

0

5

10

15

20

25

30

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

1.1

PSDA VSDA VSD FD AF/GP REA

Job

s C

ou

nt

No

rma

lize

d P

I in

cre

ase

Sorochinsko-Nikolskoe

O2-O5Pronkinskoe A4

Dolgovskoe T1

Kodyakovskoe Zl

Pokrovskoe A4

Bobrovskoe T1

Bobrovskoe O3-O6

Tokskoe T1

Samodurovskoe T1

Kodyakovskoe T1

Average value

Total jobs

Unsuccessful jobs

0

1

2

3

4

5

6

7

8

9

10

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

1.1

PSDA VSDA VSD FD AF/GP REA

Job

s C

ou

nt

No

rmal

ize

d p

ost

-aci

diz

ing

PI

Bobrovskoe B0

Bobrovskoe O3-O6

Bobrovskoe T1

Garshinskoe D5

Davydovskoe D5

Dolgovskoe T1

Kodyakovskoe Zl

Pronkinskoe A4

Pronkinskoe T1

Sorochinsko-Nikolskoe

O2-O5Average value

Total jobs

Unsuccessful jobs

10 SPE 168167

level. Two wells showed minor (9 atm) and no pressure increase when balls arrived to perforated interval. On the last well,

injectivity was too low and balls were not pumped at all. In fact, the pressure increase on later chemical diverter stages was

much higher for all three wells that had been injected with ball sealers. Fig. 17 shows a stimulation treatment on one of these

wells. Highlighted intervals showed no pressure increase when balls arrived at perforations and 30 to 32 atm increase when

two stages of chemical diverter were pumped through the perforations.

Suspected reasons for the poor ball

sealer results are multiple perforations

and poor cement quality. All three wells,

as well as most of the potential

candidate wells for acidizing treatments,

are already perforated, some of them

perforated multiple times across the

same interval. The large number of

perforations make it difficult to design

the required number of ball sealers.

Also, the cement quality is usually bad,

especially on wells with multiple

perforation operations. Ball sealers

divert flow only from holes in casing,

but behind the casing the fluid still may

find the way of least resistance to treat

the same thief interval that was just

blocked by a ball. This probably

happened on the first well, where a good initial pressure increase was followed quickly by a decline to the initial level. After

the four pilot wells, the ball sealers were no longer used and the treatment focus changed to the chemical diverters.

Polymer-based self-diverting acid The PSDA is a chemical diverter frequently used in the Orenburg region. It consists of HCl mixed with a gelling agent

and a pH-sensitive crosslinker. Initial spending of the acid during leakoff and wormholing produces a rise in pH to 2 to 3,

which initiates crosslinking and a rapid increase in viscosity. This viscosity increase creates a temporary viscous plug in the

stimulated zones and diverts subsequent acid stages to more damaged and less permeable zones. The viscosified PSDA

begins to break when pH increases to 3.5, and at pH above 5 the viscosity is reduced to about 15 cp. PSDA fluid is usually

pumped in several stages alternately with regular acid stages (Fig.17).

Laboratory testing of compatibility between PSDA and crude samples from different fields in Orenburg region showed a

tendency of sludge creation at high HCl concentrations and determined that only 5% HCl with a large volume of additives

could be used for PSDA formulation. Low acid concentration can decrease diverter efficiency by spending faster and a

creating a narrow pH interval for PSDA crosslinking. In fact, under the laboratory conditions it was difficult to observe the

PSDA viscosity gain during the reaction with carbonate material: crosslinking was quick and short lived. A few core flow

tests (CFT) were performed to evaluate the effectiveness of the PSDA diversion with a low concentration of base acid.

Permeability and differential pressure between core inlet and outlet were measured while pumping fluids through the cores. A

high inlet pressure increase was observed, which can indicate a good diversion ability of PSDA. But, because of lab

equipment limitations, it was not possible to pump PSDA through the whole core and create reach-through wormholes due to

approaching maximum working pressure for the laboratory equipment. Increasing HCl concentration will increase the chance

of good wormholing with PSDA, but because of incompatibility with crude this was not possible. The polymer nature of

PSDA is another drawback. Polymers can damage the formation if they are not fully flowed back after the treatment. Cleanup

in the Orenburg region is difficult because of the low reservoir pressure, and remaining polymer can deteriorate the

stimulation effect.

Stimulation of old wells represents the major challenge for diverter efficiency because of their previous treatments and the

potential for drained thief zones in pay intervals. Fig. 15 shows productivity after stimulation with PSDA for most fields is

less than 50% of that obtained with other technologies; in fact, the average productivity is the lowest shown. Two oil fields

achieving good results with PSDA (Tokskoe T1 and Samodurovskoe T1) have had only limited numbers of treatments with

other technologies. Results for the new wells (Fig. 16) are better and show the effectiveness of PSDA is comparable to that of

other technologies. This can be explained by two facts: new wells usually have higher reservoir pressure, which can promote

more efficient polymer flowback; and new wells usually require less diversion efficiency than old wells.

Because PSDA has not produced the desired results, its use is decreasing in Orenburg area and very few wells have been

pumped with PSDA in 2011-2012 (fig.13) due to introduction of more efficient diverting technologies.

Fig. 17. Example of combined treatment with ball sealers and chemical diverter.

0

0.2

0.4

0.6

0.8

1

1.2

1.4

1.6

1.8

2

0

50

100

150

200

21:18 21:33 21:48 22:03 22:18 22:33 22:48 23:03 23:18

Pu

mp

Rat

e,

m3

/min

Pre

ssu

re, a

tm

Time

Treating Pressure

Annulus Pressure

Pump Rate

Ball Sealers

Chemical

diverter,

stage#1

Chemical

diverter,

stage#2

SPE 168167 11

Fig. 19. The inlet core faces after exposure to VSDA: A4 formation core (left); Zl2 formation core (right).

Viscoelastic self-diverting acid VSDA is a polymer-free diverting system. It consists of HCl mixed with a viscoelastic surfactant gelling agent. The

surfactant gels as the acid spends. The increase in viscosity causes temporary plugging of the acid-etched channels to allow

continuous acidizing of the unstimulated zone (Chang et al. 2001, Taylor et al. 2003).

Fig. 18 shows a typical VSDA viscosity profile

as a function of HCl spent. A VSDA starts to

develop viscosity when the acid spends from 20%

to 12% (corresponds to 8% of HCl spent on the

figure). The fluid maintains a high viscosity as the

acid spends, so continuous diversion can be

achieved during pumping. When production

resumes, the hydrocarbon effectively breaks the

surfactant and lowers the VSDA viscosity.

The application of VSDA in Volga-Ural has

also been described for other parts of the region.

Iliasov et al. (2010) described the application of

VSDA and VSD for seven gas wells and three oil

wells in the Saratov region. The wells showed a PI

increase of 5 times for gas wells and 12 times for oil

wells. Dnistryansky at al (2012) presented data of

VSDA stimulation of a horizontal well in Orenburg

region. VSDA was placed via CT. Treatment with VSDA system resulted in a 20% production enhancement.

In a laboratory, VSDA was evaluated by linear core flow experiments using representative core samples from Volga-

Ural oil fields. The experiment procedure was similar to those described by Lungwitz et al. (2004) and Faizov et al. (2011).

Diversion ability and fluid efficiency were evaluated.

The diversion capability of the VSDA system was evaluated by the concept of maximum pressure drop ratio, dPmax/dP0,

proposed by Lungwitz et al. (2004): a ratio of the maximum pressure drop, dPmax (obtained during the pumping of a diverter)

and a baseline pressure drop, dP0, obtained during measurement of initial permeability (k). In a series of studies, Lungwitz et

al. (2004) showed that ratios greater than 1 indicate viscosity increased to create a temporary plug within wormholes and can

be considered as an indicator of diversion capability. VSDA efficiency was characterized by number of pore volumes of the

acid system required for wormhole to breakthrough (PVBT).

The recommended surfactant concentration in

VSDA is 5 to 10 vol%. Several core flow experiments

were performed with the recommended

concentrations of the surfactant (Table 3). The tests

revealed that VSDA had good diversion capability for

cores from different formations of the Volga-Ural

region. The ratios obtained varied from 2.47 to 8.01

for different cores. The tests also showed that VSDA

required only 1.2 to 2.6 pore volumes to create a

wormhole that penetrated the length of the cores;

regular acid requires up to 8 pore volumes (Table 4)

in the same conditions because of face dissolution and

lower capability to propagate wormholes. Note that

the inlet surface of the cores treated with VSDA were

free from any residue, indicating no core damage and

that diversion had occurred inside the cores (Fig. 19).

Production data provided in this paper refer to VSDA

with surfactant within the recommended concentration

range.

Compatibility tests of VSDA and crude oil were the

essential part of the laboratory testing. Because oil from

the Volga-Ural region has a strong tendency to form

sludge and emulsion when mixed with a stimulation

fluids, iron control, antisludge agents, and demulsifier

were included to achieve the compatibility (Fig. 20) that

conforms to all QAQC requirements.

0

50

100

150

200

250

0 5 10 15 20 25

Vis

cosi

ty (

cp)

@ 1

70

1/s

ec

HCl % spent

Fig. 18. VSDA viscosity development in 20% HCl as function of percentage of HCl spent.

Fig. 20. Emulsion and sludge tests results for VSDA (spent acid)

and crude oil mixed in 75:25, 50:50, and 25:75 ratios.

12 SPE 168167

TABLE 3. CORE FLOW TESTS WITH RECOMMENDED SURFACTANT CONCENTRATION IN VSDA.

Formation BHST, ⁰C Surfactant conc., vol%

Initial permeability,

md dP0, psi dPmax, psi dPmax/dP0 PVBT

A4 37 60 356.7 3.48 16.9 4.85 2.3

A4 37 75 144.5 7 56.1 8.01 1.2

Zl 51 60 0.7 399 988 2.47 2.6

T1 47 75 12.53 40.51 219 5.4 0.7

T1 53 60 77 9 69 7.67 1.5

TABLE 4. CORE FLOW TESTS WITH RECOMMENDED ADDITIVE COMPOSITION FOR 15% HCL

Formation BHST, ⁰C HCl, vol% Initial

permeability, md

dP0, psi dPmax, psi dPmax/dP0 PVBT

A4 37 15 191.5 6.3 8.2 1.3 2.4

T1 47 15 280.5 0.79 2.68 3.4 2.56

Zl 51 15 0.04 2695 1218 0.45 8.2

In total, 35 VSDA treatments have been performed in Orenburg fields from 2007 to 2012, including 23 on new wells and

12 on producing wells. Most wells have demonstrated better results than offsets treated with other viscosified diverters (Figs.

15 and 16). Although VSDA has shown better results than PSDA or other viscosified diversion techniques for Orenburg

region, it has not become a regional standard for a several reasons. The first and most important is that the depleted

formations in this region often do not have sufficient energy to initiate flow back the viscous fluid after the treatment. Later

VSDA technology was incorporated with nitrogen to form stable viscous foam for diversion and enhance flowback. The

second reason is water cut. VSDA is acidic and did not help reduce or even retain water cut at the pretreatment level. The

need for techniques to retain water-cut levels and effectively stimulate depleted reservoirs was later addressed by foam

diverters.

As a way forward for VSDA, additional core

flow tests were conducted to determine the impact

of decreased surfactant concentration on VSDA

efficiency to stimulate cores from the Orenburg

region. This step was made to further address the

challenge of the fluid flowback when acidizing

depleted formations. The surfactant concentration

was decreased to 4 and 2 vol%. Fig. 21 shows

diversion performance was not drastically affected

by reduction of the surfactant concentration. In all

experiments dPmax/dP0 was greater than 1. At the

same time, with surfactant concentration 2 vol%, a

slight decrease of the wormholing efficiency was

indicated. In particular, for a core with initial

permeability 22.3 md (T1 formation), PVBT was

3.3. Such an increase can be caused by higher

leakoff. Generally the laboratory tests with low

surfactant concentration in VSDA showed this approach should be considered beneficial, especially for massive tight

carbonates such as Zl formation and could be applied for future treatments in Orenburg oil fields to accommodate diversion,

wormholing, and flowback issues.

Viscoelastic selective diverter As noted, wells producing from Orenburg carbonate reservoirs have high water cut (Fig. 5). When acidizing a well with high

water cut or with an oil/water contact (OWC) special precaution is needed to minimize the risk of water cut increase after the

treatment. Typically, because of the acid’s affinity for water, bull heading the acid without special diverters will result in

stimulating the water zone and leaving the oil zone unstimulated. Historically, these wells were not considered as candidates

for acidizing due to lack of special technologies to divert acid away from water-saturated zones, but this changed in 2008

when VSD was introduced in the Orenburg region.

Fig. 21. VSDA performance with decreased surfactant concentration.

4.673.67

14.3

27.8

13

2.51.4

3.3 2.41.5

0

5

10

15

20

25

30

Dzl1, 5 mD,

2 vol.% VSDA

Dzl1, 7.6 mD,

4 vol.% VSDA

T1, 22.3 mD,

2 vol.% VSDA

T1, 34.5 mD,

4 vol.% VSDA

T1, 280 mD,

4 vol.% VSDA

dP

max

/dP

o

PV

BT

dPmax/dP0

PVBT

SPE 168167 13

VSD is used for matrix stimulation to divert acid away from a high–water-saturation zone and into a hydrocarbon-rich

zone. It is a water-based fluid with viscoelastic surfactant and initially has high viscosity. During the matrix acidizing

treatment it is injected into all zones; its viscosity sharply drops when it contacts oil in the hydrocarbon-saturated zones. The

dominate presence of formation brine keeps the viscosity stable in water-saturated intervals, preventing acid from being

injected into water zones and redirecting it from water- to hydrocarbon-saturated sub layers. As a result, oil-producing

formations are stimulated and water-saturated sublayers are temporarily blocked during treatment. No residual damage

remains because the material is no

polymeric. Laboratory tests with this

selective diverter were described by

Chang et al. (1998). The fluids were

pumped through two cores with

different saturations in parallel.

Before the selective diverter was

pumped, the majority of the injected

fluids went through the core with

higher water saturation because of the

relative permeability effect (Fig. 22).

Upon injection of the diverting agent,

a viscous plug was formed in the

highly water-saturated core and

degraded while flowing through the

core with lower water saturation.

Once a viscous plug was formed in

the highly water-saturated core, the

acid preferentially entered and

stimulated the core with high

hydrocarbon saturation.

Laboratory tests were performed with core samples from the Kurmanaevskoe oil field to verify applicability of VSD in

typical bottomhole conditions of the Volga-Urals region (Table 5). Two cores with similar permeabilities were used to

perform core flow tests: one was saturated with 2% KCl brine and another with kerosene. The goal was to measure

differential pressure required to initiate flow in water- and kerosene- saturated cores. The following treating schedule was

applied:

1. The initial permeability was measured (2% KCl).

2. The core was saturated with the oil or water phase.

3. Five pore volumes of VSD were injected.

4. Shut down for 10 min.

5. 2% KCl solution was injected.

6. DP required to initiate flow was measured.

High DP values during treatment indicate excellent VSD diversion ability. DP required to initiate flow in water-saturated

core is 1.7 times higher than for kerosene-saturated core. It means that during acid injection it preferably will penetrate oil-

saturated layers.

TABLE 5. DIFFERENTIAL PRESSURE RESPONSE DURING VSD INJECTION.

Fluid for core saturation

Initial permeability (2%

KCl), md

dP0 (2% KCl injection), psi

dP1 (VSD injection), psi

dP2 (required to initiate 2% KCl

flow), psi

Water 20 33.9 1322 859

Kerosene 25 27.7 1276 505

It is common practice in the Volga-Urals region to combine VSD with other diverting technologies during the treatment

(Fig. 13). In this case VSD was pumped as the spearhead stage before any reacting fluids penetrated to the formation. It

blocked potentially water-saturated zones from the following acidizing treatment. After the spearhead, the normal matrix

acidizing treatment continued with alternating stages of acid and chemical diverter. Dnistryansky et al. (2012) showed an

example of using VSD spearhead stages during matrix acidizing of the giant Orenburg oil, gas, and condensate field. While

previous acidizing treatments on the field had caused water breakthrough, no water production was observed on wells treated

with the spearhead VSD stage. Another example of using VSD in the Volga-Urals region was published by Ilyasov et al.

(2010), reporting significant water-cut decrease after six treatments with VSD; on three of them, VSD was pumped as

spearhead stage with subsequent usage of VSDA as the main diverter.

Fig. 22. Fractional flow of aqueous fluid into cores with different oil saturations

14 SPE 168167

In acidizing treatment of wells with very high water cuts (usually above 70%), VSD is used as the sole diverter for the

entire treatment. Reactive fluid is pumped between VSD stages. The VSD sections on Figs. 15 and 16 represent only the

treatments using VSD as the sole diverter; this is the reason of small VSD job count. The treatments using VSD only as a

spearhead stage are distributed on Figs. 15 and 16 among the other diverting technologies used later in the same treatment.

Well 143 Tokskoe oil field (T1 formation) is a good example of a VSD treatment in a well with high water cut. Before

treatment, the well produced 205 m3/d of fluid with 76% water cut. The source of water was not known. A matrix acidizing

treatment was then performed comprising four VSD stages with 15% HCl stages pumped between them. After the treatment,

stabilized production was 288 m3/d of fluid and water cut dropped to 60%. As a result, post-acidizing oil production more

than doubled, from 42.5 to 99.5 tons of oil per day.

Not all VSD treatments were successful; some resulted in substantial water-cut increases (red dots on Figs. 15 and 16).

The suspected reason is presence of natural fissures or channels in the cement behind the casing that links perforation with

water-saturated intervals. In this case, the size of the pathway to the water is much larger than the porous media that is a

VSD target. It is well known that viscosity is not enough to provide efficient diversion in fissures or channels. Additional

mechanical diversion (i.e., fibers or other particulates) should be considered in such cases to minimize acid flow into water-

saturated zones.

Foam diverter Foam diversion was implemented very early in the history of engineered matrix acidizing. Use of aquatic foam for

diversion is described by Smith et al. (1969). Zerboub et al. (1991) demonstrated improved application for foam diversion

and its benefits for major acidizing challenges: zone coverage, enhanced flowback, and water-cut reduction.

Often foam diversion is not considered because of logistics and equipment limitations. In the Orenburg region, foam

appears to be the most reliable diversion technique in depleted reservoirs with repeated treatments and increasing water cut.

Thus, since 2011 most matrix acidizing treatments have used foam-based diversion (Fig. 13).

Foam minimizes formation damage; diversion, on the other hand, incorporates all producing zones. Nitrogen can be used

to assist flowback of reaction byproducts, kick off the well, and put the well on production straight after the stimulation

treatment. For the best foam diversion performance, the following sequence of stages was recommended for foam diversion

in the Orenburg region:

1. Clean the near-wellbore area if necessary. Use mutual solvent to remove oil from near-wellbore region (oil destroys

foam) and water wet the formation.

2. Inject a preflush containing surfactant. The preflush displaces the mutual solvent (detrimental for foam) and

minimizes the absorption of the surfactant inside the foam.

3. Inject the foam pill. The foam preferentially plugs the high-permeability zones.

4. Shut in the well. Following the foam penetration into the matrix, a short shut-in time is helpful to attain a stabilized

diversion regime quickly.

5. Inject treating fluids containing surfactants. If surfactant is not added, the acid stage destroys foam and the diversion

effect vanished quickly.

This sequence was revised for the wells with previous acidizing treatments. Usually, the previous treatments consisted of

bullheading 0.5 to 1 m3 of 14% HCl per meter of perforation with no diverters and were performed by local workover

companies. In acid-treated wells, vugs and face dissolution can exist across the most permeable zones. In this case acidizing

treatment can start from the foam diversion

stage. It is recommended to increase the first

foam preflush and first foam diversion stage

proportionally to the amount of carbonate rock

dissolved during the previous treatment. For

example, 3.78 m3 of 15% HCl dissolves

approximately 0.3 m3 of limestone rock before

full spending. If 11.36 m3 of 15% HCl were

pumped on the previous treatment, the first foam

preflush and foaming stage should be increased

by approximately 0.9 m3 for downhole

conditions.

A number of treatments have been

performed with memory BHP gauges, which

have demonstrated that foam diversion can be

very efficient and increase bottomhole treating

pressure by up to 100 atm (Fig. 23).

Stability of the foam is another important

issue that should be designed for the treatment.

Foam stability is measured in lab conditions with

Foam

diverter

Pre

ssu

re(a

tm),

Nit

rog

en

ra

te (

smc/

min

)

Foam

diverterFoam

diverter

Effect of

possible foam

degradation

after 100 min

Fig. 23. Example of acidizing job with foamed diverter, measured

bottomhole pressure.

SPE 168167 15

a foam half-life test: foaming surfactant is added to the guar-based fluid and blended in a mixer at maximum speed to create

foam. Then, foam is poured into a cylinder and its half-life is measured. The half-life of the foam is the time in minutes taken

for the volume of clear fluid breaking out at the bottom of the foam column to reach 50% of base fluid volume. Depending on

viscosity of the base fluid, foam half-life can vary from 15 to 90 min for regular guar-based fluids with guar loading from 1.2

to 3.6 kg/ m3.

In extended treatments, foam diverter can degrade while the acid stages are being pumped; a sign of this degradation can

be decreasing pressure on the next acid stage (Fig. 23), although the decrease can also indicate acid breaking through the

damage. After evaluation of bottomhole pressure data from a number of wells, the shut-in period after the foamed diverter

stage was significantly decreased in order to gain viscosity yield and not compromise foam stability.

For low-injectivity formations, foamed VSDA is also recommended to increase stability and diversion efficiency. A

surfactant-based fluid, VSDA does not need additional foaming agents and has extended stability of 3 h or more of foam

half-life.

Foam diversion was primarily used with an application of CT placement. Acidizing was performed on different

formations with long production intervals and low reservoir pressure. The treatment sequence as well as a case study for CT

placement of foam diversion are given in the next section of the paper.

Wells producing from a deep Devonian

formation (D5) in the Orenburg region were chosen

as trial candidates for bullhead acidizing treatments

with foam diversion. The formation’s true vertical

depth (TVD) was 4200 to 4300 m, average gross

height was 3 to 8 m, and typical permeability was

from 2 to 5 md. The low reservoir pressure ranged

from 200 to 300 atm in combination with very light

crude of about 48 ⁰API. Without stimulation, wells

were producing at low oil rates and positive skin

was estimated from 5 to 15. Although based on

nodal analysis wells have shown potential for

natural flow, conventional acidizing with viscous

diverters on offset wells did not deliver desired

results. Difficulties in flowback on deep wells made

the final result of the treatment mostly dependent on

quality of flowback and kickoff rather than the

quality of the acidizing treatment itself. Five

Devonian wells were treated in 2010 as a pilot

project for bullhead acidizing with FD in Orenburg

region. Post-treatment production established

average PI increase of 4.4 times and average oil

increment of 48 tons per well (Fig. 24). The success

of these five wells made foam diversion the

regional standard for acidizing. Overall production

results on Figs. 15 and 16 showed good

effectiveness of foam diverter on new and old

wells.

Zerhboub et al. (1991) demonstrated that

aquatic foam is a selective diverter that can aid in

water-cut reduction in post-treatment production. In

the Volga-Urals region, oil-saturated layers are

usually located near water-saturated zones or have

active aquifer. Most formations produce at high

water cut and most produced fluid is water. After

2010, most of the acidizing treatments have incorporated foam diversion (Fig. 13); statistics show a trend reduced post-

acidizing water-cut increases after introduction of foam diversion techniques (Fig. 25).

Using CT for Matrix Acidizing The conventional method for matrix acidizing is bullheading. The approach is widely used but in some conditions has lower

efficiency because of nonuniform stimulation. CT has advantages over bullheading in matrix acidizing, especially for long

interval treatments:

1. Placement. CT helps place treating fluids across the entire interval. Thomas et al. (1995) using computer simulator

and real case studies showed CT placement in combination with chemical diverters yields good zone coverage in

horizontal and vertical wells completed in massive carbonate reservoirs.

0.0

20.0

40.0

60.0

80.0

100.0

120.0

140.0

0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

4.00

1 2 3 4 5 6 7 8 9 10

Q o

il,

ton

s/d

ay

PI,

m3

/d

ay/a

tm

FD

PI Before PI After Oil incremental

AF/GPPSDA

Fig. 24. Foam diversion productivity results versus other acidizing on

D5 formation.

0%

5%

10%

15%

20%

25%

30%

35%

40%

2007 2008 2009 2010 2011 2012

Av

era

ge W

ate

r C

ut

Water Cut after acidizing

Water Cut before acidizing

Fig. 25. Post-acidizing water-cut increase minimized after introduction of foam diverter

16 SPE 168167

2. Reduced risk of iron precipitation. CT allows pickling the CT string on the surface before running it in the hole, thus

eliminating the risk of iron invasion into the formation with acid.

3. CT prevents exposing the wellhead or completion tubing to direct contact with corrosive treatment fluids.

4. Integrated treatments. Associated operations can be performed as part of an integrated service prior to the matrix

treatment; for example, fill removal; acid wash or cleanout of the rathole from incompatible fluids. It is imperative

in many matrix treatments to perform the well flowback as soon as possible after the acid job. Nitrogen kickoff can

be performed right after the treatment to recover as much treating fluid from the formation as possible and put the

well into production. Production logging can be performed before and after the treatment.

5. Live well treatments. The CT pressure control equipment configuration allows the treatment on a live well. The

potential formation damage associated with well-killing operations and the corresponding loss of production time

are thereby avoided.

6. Mobile point of injection. Jetting effect can be effective in casing if a proper purpose-built nozzle tool is used.

One of the main disadvantages of CT is the low pump rate available through the string. Only 1.5-in. CT is available in

the Volga-Urals region and high friction pressure limits the maximum pump rate to 150 L/min. Dnistryansky et al. (2012)

showed that in long openhole carbonate

intervals matrix acidizing with 15% HCl

through 1.5-in. CT results in face

dissolution but no wormholes (Fig. 26).

Low reservoir pressure and high

permeability (sometimes hundreds of

millidarcies) result in high well

injectivity, and the average matrix rate

for Orenburg region is higher than 1

m3/min. Additionally to difficulties in

wormhole propagation, low pump rate

significantly increases pumping time. In

the case of PSDA, diverter may break in

situ during the treatment and the required

zone coverage may not be achieved.

To handle all the issues

encountered during the first acidizing

treatments through CT, the dual-string

pumping technique was introduced in the Orenburg region in 2009. With this technique, treating fluids are pumped into both

the CT and the annulus between the CT and tubing in the same treatment. Friction pressure in the annulus is significantly

lower than inside CT, so the pump rate can be increased significantly, increasing wormhole penetration and decreasing

pumping time. If required, diverter and main acid can be pumped at the same time. Acid is pumped at a high rate to the CT-

tubing annulus and foam is pumped simultaneously through CT across the thief zone. Thus the thief zone is continuously

saturated by foam, providing effective dynamic diversion during treatment and allowing the stimulation to be performed

selectively.

Well 608 in the Efremo-Zykovskoe oil field is one of the examples of using the dual-string pumping technique in the

Orenburg region. This well has four perforated intervals across different formations; Table 6 demonstrates properties of each

formation. The Df formation has appeared to be the thief zone based on pretreatment production logs. Low reservoir pressure,

clear thief zone, and significant depth difference between treated zones made this well an excellent candidate for matrix

acidizing through CT with foam diversion and the dual-string technique.

TABLE 6. WELL 608, EFREMO-ZYKOVSKOE OIL FIELD, PRETREATMENT WELL DATA

Formation name T1 Zl-1 Zl-2 Df

TVD, m 1734 1829 1854 1899

Reservoir pressure, atm 77 87 89 93

Reservoir temperature, ⁰C 40 40 40 40

Actual production, m3/d 58

Water cut, % 12

Actual oil production, t/day 44

Production contribution from log, % 18 18 0 64

Net pay, m 18 11.8 6.4 8.4

Expected permeability, md 25 27 24 85

0 20 40 60 80 100 120

Volume (m3)

0

0.005

0.010

0.015

0.020

0.025

Wo

rmh

ole

Le

ngth

(m

)

Zone 1

Zone 2

Zone 3

Zone 4

Zone 5

Zone 6

Zone 7

Zone 8

Zone 9

1 2 3 4 5 4 5 4 5 4 5 4 5 4 5 2 1 2

--- Treatment Fluids --- 1 - Solvent 2 - KCl 3 - Selective Diverter 4 - HCl 15% 5 - VSDA

Fig. 26. Wormhole length vs. volume. Short wormhole length indicates

predominant surface dissolution when pumping HCl at low rates.

SPE 168167 17

Fig.27. Post-fracturing production history for well 807 Zorinskoe oilfield

The treatment design excluded stimulation of the thief Df formation and focused on stimulation of T1, Zl-1, and Zl-2

formations. The following sequence of stages was used:

1. Pickle the CT on surface until returned acid has less than 2,000 ppm iron.

2. Pickle the annulus between the CT and tubing: With CT in hole, establish circulation (2% KCl + N2). Circulate 8 m3

of 15% HCl + N2 with direct circulation to surface.

3. Preflush with mutual solvent through CT across all zones to dissolve heavy hydrocarbons in the near-wellbore zone.

4. Displace wellbore fluid with 15% HCl in the CT-tubing annulus.

5. Pump surfactant solution through CT across all zones.

6. Pump foam through CT across all zones until there is a 10- to 20-atm increase in circulation pressure (sign of

diversion). Shut in for foam stabilization. Place end of CT across Df formation.

7. Pump 15% HCl through CT-tubing annulus and pump foam through CT at the same time.

8. Repeat Stages 6 and 7 until there is no acid in the tanks. Displace fluids in CT and CT-tubing annulus.

9. Kick off the well.

Unfortunately, the production log was not recorded after the treatments, so we cannot directly compare production

profiles before and after the treatment. But production results showed the PI increased more than 3 times: from 1.04 to 3.2

m3/d/atm at the same level of water cut. In general, all treatments performed with the dual-string pumping technique showed

excellent results. The thief zone must be well known before the treatment to maximize benefits of this technique.

Use of REA can help create wormholes even with a low pumping rate through CT. Dnistryansky et al. (2012) provided

an example of using REA for stimulation of depleted horizontal openhole wells through CT in the Orenburg region; gas

production increased after the treatment by 20% when compared with pretreatment data. Other methods to improve the

effectiveness of matrix acidizing through CT are described in Ways Forward section.

Acid Fracturing Typically, acid fracturing is the most effective stimulation method for carbonate reservoirs. During acid fracturing an almost

infinite conductivity fracture is being created because conductivity is formed by nonuniform etching and channeling (viscous

fingering) effect on the fracture face. Although acid fracturing has drawbacks in the Orenburg region, in many cases matrix

acidizing has been considered the preferred method; the most pronounced case is that with proximity to water-saturated

zones. As noted previously, average water cut for the region is over 50% for reasons such as bad cement, injector wells, rise

of OWC, natural fissures etc. In these cases acid fracturing is not applicable because it can increase water cut up to 100%

after stimulation if the fracture break through into a water zone or damages the cement bond (see large number of

unsuccessful jobs for AF/GP on Figs. 15 and 16). Parfenov et al. (2008) has discussed this issue for the nearby Samara region

and considered matrix acidizing to be of lower cost with same efficiency and with consideration of risk of unsuccessful

treatment, obviously more economically viable for Volga-Urals oil province.

Another issue is that Volga-Urals is a tectonically stressed area and often high minimum in-situ stress is observed in

carbonate formations. Jones (1973) performed lab experiments to determine the effect of closure pressure on storage capacity

and fracture flow in carbonate rocks. Based on the results, he concluded fracture conductivity was greatly reduced by

increases in closure pressure.

Since the deep Devonian formations produce with the least water cut, they have been considered as acid fracturing

candidates. Few acid fracturing treatments were performed on the D5 formation (Fig. 24). All have demonstrated rapid

production decline, returning to prestimulation productivity after 1.5 to 2 months. The primary reason is rapid losses in

fracture conductivity under high closure stress load and high applied drawdown pressures.

Well 807 Zorinskoe field is a typical example

of acid fracturing on the deep Devonian D5

formation. The formation TVD is 4606 m, gross

height is 28 m, net height is 4 m, estimated

formation permeability is 1 md, reservoir pressure

is 390 atm with very light crude (51 °API and

bubblepoint pressure of 328 atm). The well was

fractured with 66 m3 of 15% HCl and 17 m

3 of

cross-linked gel on a pad stage. Fracturing closure

pressure was determined with step-rate test of 770

atm, which represents the normal FG for carbonate

formations in the Orenburg region (around 0.17

atm/m). According to treatment design and

evaluation, 20 m of effective fracture half-length

was created with fracture dimensionless

conductivity equal to 18. Initially there was almost

no flow after perforating; post-acid fracturing

0.0

0.2

0.4

0.6

0.8

1.0

1.2

0 2 4 6 8 10 12 14 16 18 20 22 24 26

PI,

m3

/d

ay

/a

tm

Time, months

18 SPE 168167

production has demonstrated significant productivity increase but PI dropped rapidly after 2 months of production (Fig. 27).

One of the mechanisms suspected for this drop is fracture deterioration under high closure pressure. Abass et al. (2003) has

demonstrated that in case of high in-situ stress, an etched fracture may significantly lose conductivity as a result of creeping

effect.

Although due to risk of water

breakthrough and high stress

environment acid fracturing has been

replaced by high-volume matrix

acidizing in most fields; acid fracturing

on some massive tight formations has

demonstrated good results comparing

to matrix acidizing. The Zl formation

on Kodyakovskoe oilfield is a good

example of proper acid fracturing

candidates. Zl is a moderate deep

formation (TVD 2700–2800 m); there

is typically 45 to 60 m of gross height

with average porosity from 5 to 8% and

permeability ranging from 1 to 6 md.

The reservoir is very heterogeneous

with many interbedded tight and porous

layers. One proper acid fracture

treatment can cover and stimulate all

porous sublayers. Fig. 28 shows the

comparison of post-fracturing

production for 5 acid fracturing (AF/GP) and 13 matrix acidizing treatments. The comparison shows that in the Zl formation

of Kodyakovskoe field, acid fracturing significantly outperforms matrix acidizing in terms of PI (+33%) and oil incremental

(+50 tons/d). However, acid fracturing is still risky and proper candidate selection should be applied to minimize the risk of

water breakthrough after acid fracturing treatment.

Retarded Emulsified Acid Carbonate formations often have low matrix permeability and can be highly fissured. Long fractures in acid fracturing

treatments or deep wormholes in matrix treatments are necessary to maximize production. Navarrete et al. (1998)

demonstrated that the retarded nature of emulsified acids is useful to generate longer etched fractures or deeper wormholes

when matrix acidizing. Retardation of 14 to 19 times was demonstrated compared to HCl for acid fracturing and 6.6 times for

matrix acidizing. The retardation effect is due to the acid being an inner part of the mixed emulsion and diesel being an

external part, so acid is not spent instantly during treatment. The average droplet size of coarse emulsions is much larger than

the average pore throat size in a carbonate formation. Therefore, coarse emulsions initially attack the formation at the

wellbore surface. As they dissolve rock at the surface, they begin to form wormholes with macroscopic diameters (~0.1 to 1

mm). Once the emulsion enters the wormhole, the retardation mechanism there is similar to that of a fracture because the

average droplet size (~1 to 77 µm) is smaller than the wormhole diameter. Retardation provides better convection of acid’s

hydrogen ions to carbonate formations and tip of the wormholes, which makes them longer. The advantages of emulsified

and retarded acids are generally considered the

most for cases when the reaction is controlled by

mass transfer of hydrogen ion (H+); e.g.. mid- and

high-temperature limestone and high-temperature

dolomites. As demonstrated by Dnistryansky et al.

(2012), it also can be beneficial for acidizing low-

temperature limestone when only a low pumping

rate is available.

In the Orenburg region, REA has demonstrated

good results in matrix acidizing of the D5

formation in combination with foam diversion.

Besides the light crude and high stress gradient,

deep Devonian formations have the highest BHST

in the region, ranging from 89 to 95⁰C. As

discussed before, acidizing with foam diversion has

shown the best results in deep D5 depleted

formations. On several treatments, foam diversion

was combined with REA to propagate longer

0

20

40

60

80

100

120

140

160

180

0.0

0.5

1.0

1.5

2.0

2.5

3.0

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18

Oil

In

cre

me

nta

l, T

OP

D;

WC

, %

PI,

m3

/D

ay

/a

tm

WellPre-frac PI Post-frac PI Average PI Oil incremental

WC before WC after Average oil incr.

Acid Fracturing Matrix Acidizing

Fig. 28. Comparison of production results between acid fracturing and matrix

acidizing on Kodyakovskoe field Zl formation

0

20

40

60

80

100

120

140

0

1

2

3

4

5

6

7

#1; AF/GP #2; FD #3; FD #4; FD + REA #5; FD + REA

Wa

ter

cut,

%;

Oil

in

cre

me

nta

l, t

/d

ay

PI,

m3

/d

ay

/a

tm

Well #; Technology

PI after treatment Oil incremental, t/day WC after

Fig. 29. Comparison of different acidizing techniques for D5 formation of Davydovskoe oil field

SPE 168167 19

wormholes and establish adequate flowback of reaction products. Five treatments were performed in the Davydovskoe oil

field: one acid fracturing, two treatments with foam diversion, and two treatments with emulsified acid and foam diversion.

All the wells were stimulated immediately after drilling, treatments with REA have demonstrated a stable productivity

increase 3 times higher than those for offset wells treated with straight 15% HCl (Fig. 29).

Some acid fracturing treatments with REA performed on shallower formations (i.e. A4 and Zl) did not show significant

advantages compared to results from conventional acid fracturing with a crosslinked gel pad. The reason is that the

formations have quite low BHST (35 to 55⁰C) compared to that of D5, where a significant production increase was recorded,

and acid convection is not the biggest issue here compared to zone coverage and formation pressure depletion. Another

possible reason is that these wells

have been treated with acid fracturing

before and REA was used as a

remedial stimulation treatment for

them. Fig. 30 shows recorded

bottomhole pressure increase versus

time in log-log coordinates for one of

the remedial acid fracturing job with

REA on the Zl formation. Pressure

behavior can be interpreted as

reinjecting the fluid into an existing

fracture and fissure network. The plot

demonstrates a pressure slope of 0.6 to

0.8 that can be considered a transition

between storage and linear flow

regimes. No new fracture is opened

and most probably new areas were not

stimulated.

In spite of results in these few wells, overall production results after acid treatments with REA on new wells (Fig. 16)

showed that in most fields REA provides the highest production compared to that from other technologies. But job count is

not enough to make a final conclusion and, in the case of acid fracturing, all risks associated with this technique are still

applicable for REA treatments.

Proppant Fracturing in Carbonates There are no set rules of choosing between acid and propped fracturing. The choice is made based on experience of the

previous treatments in the area or similar formations and economic evaluation. Despite numerous fracture acidizing models

developed over the years, we still lack confidence in predicting and accurately modeling the outcome of an acid fracturing

treatment. Fluid leakoff and reaction rate are the most unpredictable variables. On the contrary, predictability of propped

fracturing where nonreactive fluids are pumped is much higher. Several criteria still could be formulated that can help to

choose between two methods. Propped fracturing treatments are more favorable if any of the following criteria are present:

- Solubility of the formation is low.

- The rock has high closure pressure.

- Formations are relatively homogeneous.

- There is a low acid reaction rate (i.e., cool dolomites with BHST less than 65⁰C).

- Low formation permeability requires long fracture length for optimum production.

- The rock softens or creeps after contact with acids, resulting in poor fracture conductivity.

On the contrary, acid fracturing is preferred under the following conditions:

- Formations that are naturally fractured where placing proppant are associated with significant risk of premature

screenout.

- Formation permeability is relatively high.

- The well construction mechanically will not accept proppant.

As stated before, if the zone of interest is close to gas- or water-bearing formations, matrix acidizing will be an optimum

choice over any kind of fracturing operation.

Another risk associated with proppant fracturing in carbonate formation is proppant embedment. If carbonate rock is

weak, proppant granules can be forced into fracture walls, thus reducing propped fracture width. A series of laboratory tests

have been performed on an actual core sample from one of the shallow carbonate formations in the Orenburg region to

evaluate the severity of proppant embedment. An estimated closure stress was applied for 20 h onto two prepared core

samples with a proppant layer between them. After releasing the pressure, a laser profilometer was used to quantify proppant

embedment. Fig. 31 is an example of visualized results for one of the cores. Table 7 shows overall results of performed tests.

Analysis shows that after applying 250 atm pressure to 20/40-mesh proppant, the average embedment into the carbonate core

samples were from 15.4 to 25.6 µm. This is negligible compared with 20/40-mesh proppant grain diameter (0.571 mm or

571,000 µm) and the conclusion was made that proppant fracturing is applicable in the interval of core sampling.

1

10

100

0.1 1 10

P bars

t(min) after start of pumping (Cycle1)

-0.2

0.0

0.2

0.4

0.6

0.8

1.0

Slope

<< Pnet(BHP) << t.dP/dt <<Pnet(Model) Slope >>

slope= 0.80

slope= 0.65

Pumping Time (min)

Fig. 30. Log-log plot of bottomhole pressure versus pumping time

20 SPE 168167

Fig. 31. Axonometric perspective of core sample 3

after proppant embedment test

Acid fracturing in most cases is considered safer in

terms of operational risks since no proppant is pumped

and there is no inherent risk of proppant flowback. On the

other hand, in deep formations with high stress, proppant

can create a more conductive (and longer) channel than

can be retained after closure of an acid-etched fracture, so

production decline will not be as sharp as after acid

fracturing (Fig. 27). There are many exceptions to the

“rule of the thumb” that fracture acidizing should not be

applied to high-stress conditions. For example, Burgos et

al. (2005) reported successful carbonate acid fracturing results in depths of 4,876 to 5,181 m using surfactant-gelled HCl with

organic acid blends.

To date, authors are aware of only two proppant fracturing treatments on carbonate formations that have been performed

in Orenburg and close-by regions. Both treatments were pumped as designed but failed in terms of post-fracturing

production.

• One treatment was pumped in an openhole shallow gas reservoir and resulted in wellbore collapse after the

treatment. Long workover operations were required to clean the wellbore of reservoir debris. These operations

resulted in a few hundred cubic meters of unfiltered workover fluid lost into the depleted gas reservoir. It was

not surprising that production targets were not achieved after the well was put on production.

• Another treatment was a combination of acid fracturing with proppant fracturing on an oil well. At the

beginning, a conventional acid fracturing treatment with a viscous pad was pumped followed by proppant

fracturing without interruptions. The aim was to fill the etched fracture with proppant that would minimize risk

of fracture closure and provide long-lasting production. Unfortunately, severe proppant flowback was observed

after the treatment; it limited production and frequent workover operations were needed to clean the wellbore.

We are very limited in the number of potential carbonate well candidates for proppant fracturing in the area, primarily

because of their proximity to the water-bearing formations. However, we still consider this type of treatment because of the

potential benefits that could be achieved in formations with moderate permeability. Recent experience has shown that

candidate well should be cased with good cement bond. Filling of the created acid fracture with proppant should be avoided

because the fracture face will be significantly etched by acid and the formation may not be able to apply enough stress on the

proppant pack to keep it from flowing.

Ways Forward Not all acidizing aspects have been addressed in Orenburg region over the acidizing project period described in this paper.

High water cut in combination with highly mineralized water (typical formation water specific gravity is 1.17) often results in

formation of inorganic scale that deposits in the critical matrix, perforations, and downhole equipment; the usual

consequences are faster production drop and reduced effect from acidizing treatment. Generally a low-temperature

environment produces rather heavy crudes with paraffin and asphaltenes that can deposit in the critical matrix and

completion.

TABLE 7. PROPPANT EMBEDMENT TEST RESULTS.

Core sample Max cross-

section depth, µm

Average cross-section embedment,

µm

100-mm2 area

average embedment,

µm

1 64.6 15

15.4

1 48.2 18

1 57.7 12

1 65.8 18

1 64.2 14

2 69.2 15

17.8

2 52.3 18

2 56.9 18

2 59.2 19

2 67.6 19

3 88.3 35

25.6

3 71.6 22

3 63.7 25

3 56.1 21

3 71.9 25

SPE 168167 21

A number of laboratory tests have confirmed that high–water-cut wells tend to form mixed deposits, inorganic scale plus

organic heavy chains. Figs. 32 and 33 demonstrate mixed deposits from the Sorochinsko-Nikolskoe oil field. Heavy

hydrocarbons and scale crystals are clear on the picture taken by the microscope. X-ray diffraction (XRD) analysis has

revealed sulfate (gypsum), halite, and carbonate precipitation. The gypsum is almost insoluble in HCl or chelates and should

be inhibited with remedial squeeze treatments or during matrix acidizing. One of the ways forward to properly solve the

problems of mixed deposits is complex treatment with organic solvents or organic solvent emulsions and scale inhibitor

inside the main acidizing fluid. The advantage of having phosphonate inhibitor added to the acid solution is that additional

squeeze treatments are eliminated, and well is protected against scale formation directly after the treatment. The amount of

inhibitor is calculated based on expected water cut and general water mineralization. Inhibitor return should be monitored

when the well is put on production and squeeze treatments repeated in case the protection ends.

A few years ago a horizontal well drilling project was started in oil fields in Orenburg region. To date, only a few

horizontal wells were stimulated with CT; however, in 2014 16 horizontal wells are planned for stimulation and all of them

will be completed either with matrix acidizing through CT or multistage acid fracturing with sleeved completion systems. For

both of them, a number of options should be available in advance to make this stimulation more effective. Implementation of

a CT string with larger OD of 1.75 or 2 in. can increase the maximum pumping rate through CT, which will be beneficial in

these depleted fields. Seven horizontal wells are planned on depleted A4 formation in the Pronkinskoe oil field, which is a

massive carbonate formation suitable for acid fracturing. However, formation pressure at the moment is only 40 to 60% from

initial and massive acid fracturing treatments on horizontal wells need to be flowed back effectively. For that purpose, acid

fracturing with high-rate nitrogen pumping is planned to aid flowback and ensure proper kick-off after the treatment. Kritzler

et al. (2002) has discussed acid fracturing energized with nitrogen to 60 to 70% foam quality as an optimum stimulation

method for low-pressure, low-temperature carbonates; this helps bring about flowback and longer fracture propagation

because of the retardation effect of energized acid.

CT applications in openhole horizontal wells generally allow more equal stimulation of the horizontal section in a timely

manner. Inflatable packers will be implemented to provide mechanical diversion in long intervals with known thief zones.

Another option for CT applications in horizontal open holes and slotted liners is to combine the acidizing chemical reaction

with wellbore cleanout using jetting energy. Jetting is performed with a jetting nozzle and organic solvent as a wellbore

cleanout stage before the main acidizing treatment.

Conclusions The paper is summarizing experience gained during six years of acidizing treatments in Orenburg region. Different pumping

techniques and stimulation technologies were implemented to increase effectivness of carbonate acidizing in challenging

environment of this region. The following conclusions can be formulated:

1. A rigid and comprehensive QAQC standard for acid stimulation enables the service companies to perform

consistently at a higher service delivery level.

2. Most of the performed treatments are bullhead matrix acidizing. Coil tubing (CT) placement is rarely performed

because of pump rate limitations, but it has some unique benefits like simultaneous pumping through CT and CT-

tubing annulus. The number of acid fracturing treatments decreased during the last 2 years because the lack of good

candidates.

3. Degradable ball sealers showed poor diverting efficiency due to multiple perforations and poor cement quality.

4. The polymer-based self diverting acid provides satisfactory results on new wells but failed on old wells comparing

with other diverting technologies.

5. Viscoelastic self-diverting acid has demonstrated better production results than other viscosified diverters but it

needs sufficient energy to to initiate flow back the viscous fluid after the treatment. These challenge can be

Fig. 32. Mixed deposits from ESP at Sorochinsko-

Nikolskoe oil field under microscope Fig.33 XRD analysis of scale from Sorochinsko-Nikolskoe field, O4 formation

22 SPE 168167

overcome by using nitrified VSDA or/and by decreasing the surfactant concentration.

6. Viscoelastic selective diverter can provide a temporary blockage of water saturated zones during matrix acidizing. In

Volga-Urals region VSD is often combined with other diverting technologies during the treatment. Some treatments

with VSD resulted in substantial water cut increase. The suspected reason is presence of natural fissures or channels

in the cement behind the casing.

7. Foam diverter appears to be the most reliable diversion technique in depleted reservoirs with repeated treatments

and increasing water cut. Overall production results showed good effectiveness of foam diverter on new and old

wells. Additionally, reduction of post-acidizing water cut increases was noticed after after introduction of foam

diversion techniques.

8. The use of coil tubing with foam diverter and dual-string pumping technique provides excellent production results

when location of the thief zone is well known.

9. Most of the reservoirs in Orenburg region are not suitable for acid fracturing due to 2 main reasons: proximity of

water saturated zones and high minimum in-situ stress. However, some massive tight formations demonstrated

better production results after acid fracturing comparing to matrix acidizing. Further implementation of acid

fracturing technique should be focused only on such formations.

10. Retarded emulsified acid in combination with foamed diversion has demonstrated excellent production results for

matrix acidizing of deep and hot D5 formation. Achieved productivity index is 3 times higher than offset wells

treated with straight 15% HCl.

11. Proppant fracturing can be applied on carbonate formation if proper candidate selection and treatment design

considered. Recent experience has shown that candidate well should be cased with good cement bond. Filling of the

created acid fracture with proppant should be avoided because the fracture face will be significantly etched by acid

and the formation may not be able to apply enough stress on the proppant pack to keep it from flowing.

Acknowledgment The authors thank Rosneft and Schlumberger for their support and permission to publish this paper. The authors also

acknowledge the specialists in the Orenburgneft geological departments for their continuous support in implementation of

new technologies in the Orenburg oil fields. The authors express their appreciation to the Schlumberger Well Services and

Well Intervention teams in Buzuluk and particularly to Konstantin Basanov, Evgeniy Klimov, Evgeniy Metlyaev, Rim

Samigullin, and Marina Stepanenko for their work and contribution to this paper. Finally, we acknowledge the team of

Schlumberger Client Support Laboratory in Tyumen for its continuous support of acidizing operations in the Volga-Urals

region, especially Alexey Borisenko, Bernhard Lungwitz, and Sergey Parkhonyuk.

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