The Application of Hydraulic Fracturing and Acidizing Stimulation Technology and

Its Future Trend in Complex Natural Gas Fields in China

Lei Qun, Jiang Tingxue, Xu Yun, Ding Yunhong, and Wang Xin

(Research Institute of Petroleum Exploration and Development – Langfang, PetroChina Lang fang City of

Hebei Province 065007)

Abstract: Since the year of 2000, the gas production in China has been increasing dramatically as a result of

the large-scale application of the advanced practicable fracturing and acidizing technology, of which the annual

averaged increment being more than 16%. In view of the complexity of natural gas fields in China, such as

low-permeability sandstone, carbonate, fissured volcano and ultra-high temperature and in-situ stress, etc, the

main fracturing and acidizing technologies and their countermeasures corresponding to above mentioned

formation types are put forward in the paper.

Normally, the characteristics of low-permeability sandstone gas field are summarized as

low-porosity(<10%), low-permeability(<0.1×10-3µm

2), low-bearing(Sg<50%), thin-multilayer and complex “Five

Sensitivities”, etc. The key difficulty is how to maintain effective long-term fracture conductivity and how to get

an uniform profile stimulated vertically in case of multilayers. And the main technologies formed include

fracturing and acidizing technology to enhance the period of stable production and separate layer fracturing

and acidizing technology, of which, the former consists of low-damage fracturing material(ultra-low

concentration CMHPG, alcohol super grade guar fracturing fluid, emulsified fracturing fluid, etc.), experimental

study of long-term fracture conductivity and the control method of the relative factors, dimensionless proppant

coefficient optimization and design method and “artificial fracture network ” fracturing method, etc. The latter

consists of anti-sand-seize multistage packer separate layer fracturing and selectively separate layer

fracturing with the seal balls put in pad fluid, etc.

On the other hand, the characteristics of carbonate gas field are summarized as complex storage types,

strong anisotropy, high Young’s modulus, etc. The key difficulty is how to get a deep penetration fracture length.

And the main technologies include surface cross-linked acid deep acid fracturing, gelled acid or emulsified acid

with multi-stage injection sealed by fracture closure acidizing technology and hydraulic sand fracturing

technology. Nowadays, Surface cross-linked acid fracturing combined with proppant fracturing technology is

under pilot experiment.

Thirdly, the characteristics of volcanic gas field are summarized as poor physical property of

matrix(K<0.02×10-3µm

2, porosity<4.0%), densely distributed natural fractures, high in-situ stress, high Young’s

modulus and thick pay layers, etc. The key difficulty is how to create the artificial major fracture in order to

connect the different microfissure systems. And the main technologies include large-scale proppant fracturing

technology, consisting of mini fracturing before main frac, physical modeling technology of artificial fracture

creation and extension in naturally fractured reservoir, small particle size proppant technology, spiral mode or

slug mode of proppant pumping schedule and real-time control of net pressure technology, etc.

While the abnormal high temperature and high in-situ stress gas fields are mostly encountered in low

permeability sandstone gas filed, carbonate gas filed and volcano gas filed, and the key difficulty of fracturing

and acidizing lies in the fact that how to improve rheology characteristics of high temperature fracturing fluids

and how to effectively reduce acid-rock reaction velocity so as to get a highly penetrated fracture length. In

addition, how to effectively reduce well head treating pressure is another difficulty encountered most frequently.

Correspondingly, the main technique formed is the heavier fracturing fluid and acid fluid technique which can

withstand high temperature.

What’s more, Several countermeasures on site are developed in order to improve the effectiveness of

stimulation treatments corresponding to above mentioned formation types, such as field quality control

technique, “three variance” fracturing fluid, proppant slug technique, comprehensive loss control technique,

comprehensive fracture height control technique, simplified mini-fracture technique and risk management as

well. It has a great significance not only ensures treatment success but also maximal post-stimulation

performance.

An excellent result is expected after applications of above mentioned stimulation technologies in targeted

gas fields, with the corresponding daily gas rate and reserves increasing significantly, which improves the pace

of gas exploration and development, now it is just at the peak time in China.

And the future development tendencies are mainly focused on coil tubing fracturing and acidizing technique,

horizontal well and multiple well bore fracturing and acidizing technique and fracture diagnostic technique

under the condition of multiple fractures,etc.

Key words: complex gas field; sandstone gas reservoir; carbonate gas reservoir; volcanic gas reservoir;

abnormal HPHT; post-frac stable effective period; zonal fracturing; depth acid fracturing; proppant fracturing for

carbonate reservoir; control of principal fracture; heavier fracturing and acidizing fluid system

0. Introduction

In recent years, the low-permeability hydrocarbon reservoirs have been presented the tendency of rapid

growth both in resources and reserves in China, for each year, 60% of the newly proved reserves are of such

type. For a significant portion thereof, fracturing and acidizing is demanded for making the unique

contributions.

In particular, along with the deep-going of the local gas exploration and development, fracturing and

acidizing will be challenged by more complicated objects of various kinds, for instance, clastic rock, carbonate

rock, volcanic, etc. Whereas these reservoirs are largely different in lithology, physical properties, rock

mechanics, earth stress, and development extent of natural fractures, the stimulation technologies to be

deployed must be differentiated strictly in view of availability and feasibility. Moreover, during the execution of

fracturing and acidizing, each of the three types of reservoirs mentioned above would face abnormal HPHT

holes, notwithstanding the difference in the extent. In other words, the fracturing and acidizing would keep

challenging the limits of various parameters, for instance, a permeability below 0.01×10-3µm

2, a hole depth

over 7,000 m, a pore pressure coefficient larger than 2.0 MPa/100m, an in-situ minimal horizontal stress

exceeding 140 MPa, or a temperature topping 180°C.

This paper summarizes, in a systematic manner, the evolution and application of fracturing and acidizing

technologies for the complicated gas fields of various types in China during recent years. Also, in combination

with the latest advances around the globe, it puts forward the next step of such technologies in China, hopefully

to further uplift the stimulation performance as well as the exploration and development proficiency of the local

complicated gas fields.

I. Distribution of complicated tight gas fields and their general features

Amongst the total gas resources of China, the tight ones take up a portion of more than 43%, which are

mainly seen in such basins as Songliao, Ordos, Sichuan, Junggar, and Tarim. In recent years, as driven by the

successive breakthroughs in exploration technology and the sustained improvement in geological theory, the

exploration targets have transited from the structural formations to the lithologic ones; that is, the exploration

realm has been expanded steadily. By now, 192 tight gas fields have been discovered, including 25 giant ones,

e.g., Kela 2 and Sulige. Generally, three trillion-class gas provinces have come on scene, namely, Changqing,

Sichuan, and Tarim.

In the following, the reservoir features of the main types are summarized one by one.

(1) Tight clastic reservoirs

The two typical ones are the Sulige gas reservoirs in Changqing and the Xujiahe gas reservoirs in Sichuan.

1) Sulige gas reservoirs in Changqing

The general reservoir features are as follows: 1) Low permeability: normally less than 1×10-3µm

2; 2) Low

formation pressure: pressure coefficient normally lower than 0.9 MPa/100m; 3) Strong anisotropy; 4) Multiple

thin layers, generally 3 or more layers; 5) Basically no gas yield unless through fracturing; 6) The post-frac

steady yield is low, normally falling within 0.5 ~ 2.0×104m

3/d;

2) Xujiahe gas reservoirs in Sichuan

The general reservoir features are as follows: 1) Low porosity: normally less than 10%; 2) Extra low

permeability: the permeability of matrix normally falls within 0.025 ~ 0.16×10-3µm

2, and mostly less than

0.1×10-3µm

2 (with the effective permeability ranging within 0.019 ~ 0.088×10

-3µm

2); 3) Low formation pressure:

pressure coefficient normally lower than 1 MPa/100m; 4) Multiple thin layers, generally 2 or more layers; 5)

Basically no gas yield unless through fracturing; 6) The post-frac steady yield is extra low, normally falling

within 0.1 ~ 1×104m

3/d.

(2) Carbonate reservoirs

Here, Tarim reservoirs may be taken as examples. Normally they feature low porosity (with the porosity of

matrix normally less than 9%), low permeability (normally less than 50×10-3µm

2), deep holes (normally above

6,000 m), high Young’s modulus (normally above 50,000 MPa), strong anisotropy (natural fractures develop to

different extents), and complicated reservoir types (porous, fissured, crevice-cavity type, etc.).

(3) Volcanic reservoirs

Xushen deep volcanic reservoirs in Songliao Basin may be taken as examples. The general features are as

follows: extra low porosity of matrix (less than 4.0%), extra low permeability (lower than 0.02×10-3µm

2), super

high temperature (above 180°C), developed natural fractures, high earth stress (stress gradient above 0.022

MPa/m), high Young’s modulus (40,000 ~ 70,000 MPa), and large vertical pay zone thickness (normally above

40 m).

(4) Abnormal HPHT reservoirs

As stated above, the focus is to challenge the limits of various parameters. The preceding text may be

consulted.

2. Main difficulties and solutions for the stimulation of complicated tight gas fields

As for the 4 types of reservoirs, each presents its unique hard nuts in view of fracturing and acidizing, and

the solutions are put forward in the following;

(1) Tight clastic reservoirs

Featuring a low permeability, such reservoirs have quite small pore throats; besides, generally the natural

fractures don’t develop, and basically multiple thin layers exist. In view of simulation by fracturing and acidizing,

the hardest nut to crack is how to maximize the post-frac stable effective period and how to get more vertical

layers stimulated under the low-damage precondition.

In this regard, the overall solutions adopted include: (1) low-damage fracturing material (ultra-low

concentration carboxymethyl guar gum frac fluid, alcoholic super guar frac fluid, emulsified frac fluid, etc.); (2)

the experimental study of long-term fracture conductivity and control method for correlative parameters; (3) the

optimal design of dimensionless proppant coefficients; (4) the “fracture network” fracturing method; (5) the

zonal fracturing by multi-stage packers which could avoid sand jamming; and (6) the innovative selective zonal

fracturing with seal balls placed in pad fluid, etc.

(2) Carbonate reservoirs

Despite being complicated and highly varied, such a type is principally featured by double or triple media.

Moreover, the matrix presents a high Young’s modulus. The pivotal difficulty lies in how to actualize deep

penetration and consequently get various crevice-cave systems communicated with each other.

In this regard, the overall solutions adopted include: 1) the depth acid fracturing by surface cross-linked

acid; 2) the closed-fracture acidizing by multi-stage injection of gelled acid or emulsified acid; 3) the hydraulic

proppant fracturing; and 4) the experimental study and test on acidizing and fracturing technology by surface

cross-linked acid together with proppant.

(3) Volcanic reservoirs

Principally, volcanic reservoirs are featured by developed natural fractures, abnormal high temperature,

and big reservoir thickness. The key difficulties rest with the availability of high temperature resistant frac fluid

as well as the creation of the artificial principal fracture for getting various microfissure systems communicated.

In this regard, the overall solutions adopted include: 1) the large-scale proppant fracturing; 2) the mini-frac

piloting; 3) the physical simulation of artificial fracture creation and extension in fissured reservoir; 4) the small

particle size proppant; 5) the spiral or slug-mode proppant pumping; 6) the control of fracture height by

high-viscosity gel slug; and 7) the real-time control of net fracture treatment pressure, etc.

(4) Abnormal HPHT reservoirs

As for such type of reservoirs, it is hard to satisfy the design specifications due to the hard truths, e.g.,

abnormal high pore pressure and high in-situ stress, restricted treatment pressure and parameters. How to

effectively reduce wellhead treating pressure is the main difficulty faced by fracturing and acidizing.

In this regard, the overall solution adopted is represented by the heavier fracturing and acidizing fluid which

can withstand high temperature (> 180°C). In addition, the optimization techniques for large-diameter injection

tubular, high pressure resistant wellhead, and pumping equipment are major considerations.

3. Methods: study on stimulation of complicated gas fields by fracturing and acidizing

Irrespective of the type of complicated gas fields, the optimal design of fracturing and acidizing shares

common points, although the in-situ execution focuses on different aspects. The related contents are

expounded as follows:

(1) Pre-treatment reservoir appraisal technology [1-2]

Apart from the application of the conventional drilling, logging, and test data, key advances have been

acquired during recent years in view of the constant-rate mercury injection for cores of reservoir, rock mineral

ingredients analysis, nuclear magnetic resonance test on saturation of moveable fluids, and inversion of

reservoir parameters based on fracturing and acidizing treatment information. In addition to the emphasis on

the comprehensive appraisal of reservoir in macroscopic, microscopic, dynamic and static perspectives,

longitudinal and transverse comparisons are employed in view of lithology, physical property, electrical

behavior, hydrocarbon bearing property, etc.

The constant-rate mercury injection information could make us know not only the conventional pore throat

data, but also the knowledge as to the development of natural fractures; the rock mineral ingredients analysis

could present the details concerning the mineral constituents and sensitivity of rocks in the reservoir; from the

nuclear magnetic resonance test data of moveable fluid saturation, it is possible to get to know the flowability of

underground gas inside the rock pores; with the fracturing and acidizing treatment parameters as well as the

pressure drop data, detailed information could be acquired as to, for example, reservoir permeability,

comprehensive filter loss coefficient, closure stress, closure time, and rock mechanics parameters.

Table 1 Example of rock mineral ingredients analysis results: cores from Baoqian 1 Well of Xujiahe, Sichuan

Basin

Mineral classification and content, % Specimen

No. Interval, m

Quartz Potassic

feldspar Plagioclase Calcite Dolomite Halite Pyrite

Total of

clay

minerals, %

1 1 10/24 (1402.62) 47.2 12.9 12.5 / / / / 27.4

2 1 13/24 (1402.92) 52.2 5.4 20.1 / / / / 22.3

3 1 17/24 (1403.22) 64.5 5.5 12.1 3.6 / / / 14.3

Average content, % 62.57 16.10 0 21.33

Note: The constituents of clay minerals are mainly represented by the illite-montmorillonite mixed layers (above 70%),

followed by chlorite (below 30%)

Figure 1 Example of X-CT scanning image for cores from Long 102 Well of Yumen: development of fissures

and solution pores

Figure 2 Example of environmental scanning electron microscope image for cores from Long 8 Well of Yumen

Oilfield: old-age petrifaction of feldspar

(Fixed-point observation and study on damage of frac fluid may be unfolded before and after the soaking of frac fluid)

Figure 3 Example of constant-rate mercury injection curve for Xujiahe qy-01 Well

in Sichuan (non-developed natural fractures)

Figure 4 Example of nuclear magnetic test on moveable fluid for Xujiahe Baoqian 001-1 Well in Sichuan (a small

quantity of moveable fluids)

(2) Experimental technique for fracturing and acidizing

Mainly speaking, the experimental techniques consist of the fracture damage assessment and frac fluid

optimization, the physical simulation of artificial fracture propagation under natural fracture conditions, the

viscous fingering simulation by transparent parallel panels, and the experimental assessment for gas

conductivity and long-term conductivity.

1) Fracture damage assessment method

Figure 5 Illustration of fracture damage assessment method

With the “three-step” method shown in Figure 5, it would be quite convenient to test the damages after

different frac fluids flow through the fractures, thus optimizing the low-damage frac fluid system.

2) Physical simulation technique of artificial fracture propagation regularity under natural fracture conditions

With a 30 cm × 30 cm× 30 cm artificial core, it is possible to simulate the correlation between artificial

fractures and natural ones under different approach angles (θ) and horizontal stress differences.

Figure 6 Simulation of the correlation between artificial fractures and natural ones

Figure 7 Lab result of physical simulation of artificial fracture propagation

As shown in the simulation, generally the bigger the approach angle (θ), the larger the horizontal stress

difference, and the easier for artificial fractures to penetrate the natural ones. In the opposite case, it would

incline to slide inside the natural fractures or be incapable of penetrating at all.

3) Physical fingering simulation technique by transparent parallel panels

Such simulation may be employed for probing into the viscous fingering regularity, thus forming the basis

for the control of frac fluid flowback parameters as well as the proposal and application of the innovative

technique of activated water fingering fracturing. According to the fingering regularity resulted from in-lab

experiments, the length would keep extending along with the elapse of time, while the height would

progressively come to stabilization.

Figure 8 Unsteady-state development process of fingering at the viscosity ratio of 90:1

Figure 9 Pseudo-steady-state development process of fingering at the viscosity ratio of 90:1

Figure 10 Height vs. time development regulation for the fingering zone

Figure 11 Length vs. time development regulation for the fingering zone

4) Experimental assessment method for gas conductivity and long-term conductivity

At present, the gas conductivity may take into account Darcy and non-Darcy flow effects. The long-term

conductivity may assume 6 closure pressures and 300 hours (50 h test under each closure pressure). Also,

steel plate or core plate (embedment factor to be considered) may be taken as the alternative fracture wall

surfaces.

According to gas conductivity test, given the identical conditions, the gas conductivity is 1.5 ~ 2.5 times

higher than that of the fluid conductivity (with distilled water); the ratio between long- and short-term

conductivity ranges between 1.3 ~ 5.5, which would be much higher under the conditions of high closure

pressure and core plate.

Figure 12 Comparison between long- and short-term conductivity with 4 common types of proppant in

Changqing

Figure 13 Gas conductivity (permeability) experimental result

(3) Technology concerning fracturing and acidizing material

In recent years, the fracturing and acidizing materials employed by the complex tight gas fields mainly

include: (1) ultra-low concentration carboxymethyl guar gum frac fluid system; (2) alcoholic super guar frac

fluid system; (3) heavier frac fluid and heavier acidizing fluid system; (4) surface cross-linked acid system.

In the following, details are provided for the ultra-low concentration carboxymethyl guar gum frac fluid

system and the surface cross-linked acid system.

1) Ultra-low concentration carboxymethyl guar gum frac fluid system

The major advantages of such system are represented by low concentration, small quantity of residues,

and low damage from residual gum. � Given the intermediate or low temperature (< 90°C), the lower

threshold of concentration would attain 0.15 ~0.22%, as compared with the normal consumption of

conventional frac fluid, i.e., 0.3 ~0.45%; � Given the high temperature (120 ~ 190°C), the lower threshold of

concentration would attain 0.4 ~ 0.6%, as compared with the normal consumption of conventional frac fluid, i.e.,

0.8 ~ 1.0%; � Satisfactory flexibility, slow settling, and high efficiency in longitudinal propping; � Low

frictional resistance (equivalent to 20 ~ 30% of that of clear water).

Figure 14 Elasticity test illustration of 0.22% CMHPG frac fluid

(blended with 40% ceramsite, no settling for 4 h at 90°C)

Figure 15 Temperature- and shearing resistance of carboxymethyl guar gum frac fluid at high temperature

2) Surface cross-linked acid system

Just like frac fluid, the surface cross-linked acid system could realize cross-linking and gel breaking control

at the land surface. Whereas it features high viscosity (> 100 mPa.s) and low filter loss, the acid-rock reaction

rate is 2 ~ 3 magnitudes lower than that of conventional acid system. Consequently, it could raise the effective

acting distance of the acidizing fluid, thus attaining the goal of deep penetration.

Figure 16 Conductivity test result of acid-etched fissures of surface cross-linked acid

�4� Optimal design technology of fracturing and acidizing

Mostly, optimal fracturing design adopts the dimensionless proppant coefficient method, which, as compared with the

conventional methods, is in pursuit of not only the long fractures but also the appropriately high conductivity for the tight gas

reservoirs.

Upon predication of the yield of gas reservoirs after fracturing and acidizing, consideration is rendered to the influences

from fractures’ long-term conductivity and non-Darcy effect [3]

.

In terms of the zonal fracturing method, provided the sheltering and zone-separating conditions are available, the

multi-stage packers are adopted which could conduct zonal fracturing to four layers at one time; Here, Figure 17 shows the

analysis of barrier sheltering conditions.

Figure 17 Example of barrier thickness and earth stress requirement for zonal fracturing in east zone of Sulige

of Changqing

Provided there are lots of thin layers, and it is impossible to unfold zonal fracturing with packer, the selective

zonal fracturing with seal balls placed in pad fluid may be employed. Getting rid of the restrictions of the

conventional seal ball fracturing, this technological process turns the past two or more runs of proppant

fracturing into just one run. The gist lies in that the seal ball-injection moment is shifted to a time span in the

midway of pad fluid; prior to the formal proppant fracturing, low-viscosity linear gum and/or activated water is

used for fully displacing one wellbore volume; after that, the pumping is properly shut down; finally, the formal

proppant fracturing could be conducted. In the case of fracturing of multiple thin layers, multiple ball-injection

runs could be attempted during the pad fluid stage. In such case, a lower flow rate shall be schemed, and the

flow rate shall maintain constant in order to judge whether any additional layer is fractured or not. This

technology evades the weak points of the conventional seal ball fracturing (e.g., blindness, proppant

interference from inter-layer communication, etc.), and is thus of theoretic and practice significance in

improving the degree of success in fracturing, controlling fracture height, enhancing the propping profile, and

improving the post-frac performance. The preliminary use on site has demonstrated the suitability, and in-situ

operability; i.e., it is suitable for the efficient fracturing of the extra tight reservoirs with interbedded thin layers.

�5�Matching techniques for in-situ treatment of fracturing and acidizing

In fact, the matching techniques play a significant role in transforming the optimal design into the optimal

treatment and optimal results. For instance, the in-situ entire-course quality control technique, the principal

fracture control technique, the “three variation” frac fluid technique, the proppant slugging technique, the

combined loss control technique, the comprehensive control technique on fracture height, the in-situ simple

test technique, the risk and emergency management technique, so on and so forth, have assured the

successful treatment of the aforesaid fracturing and acidizing packages and maximized the post-frac

performance.

Below, let’s have a scan of several techniques which have presented new advances during recent years,

e.g., the proppant slugging technique, the principal fracture control technique, and the comprehensive fracture

height control technique.

1) Proppant slugging technique

Such a technique has evolved during recent years: 1) Based on the step decline of the mini-frac pilot test,

the near-wellbore frictional resistance is tested, which in turn determines the magnitude and concentration of

proppant slug; the higher the near-wellbore frictional friction, the larger the magnitude and the bigger the

concentration, and vice versa; 2) For sand slugging, sometimes non-cross-linked linear gum or activated water

is employed, to enhance the grinding effect and provide a chance for the slugged proppant to settle down onto

the bottom of fractures, thus playing the role in controlling fracture height.

2) Principal fracture control technique

In the case of a carbonate or volcanic reservoir where natural fractures develop, the principal fracture

control technique is crucial. During recent years, the principal fracture control technique has attained such new

advances as: � Proppant slugging; � Highly viscous gel to reduce filter loss firstly and then increase flow

rate (also raise the net fracture pressure); � Real-time control of net fracture pressure (to avoid the fracturing

action on natural fracture);� Mixed different grain size proppant. With such a technique, the small grain size

proppant or pulverized sand/ceramsite is blended, at a certain ratio (normally below 10%, varying properly

dependent upon the development degree of natural fractures), into the conventional grain-size proppant; if the

fracture encounters a natural fracture (which features higher filter loss and faster absorption of frac fluid), the

small grain size or pulverized ceramsite/sand would incline to enter the seam of the natural fracture, thus

plugging up the natural fracture; so long the designed ratio matches with the development extent of natural

fractures, the previously blended small grain size proppant or pulverized ceramsite/sand would get into the

natural fractures almost completely; in the midway of fracturing treatment, they would reduce the filter loss and

extend the principal fracture; and, at the end of the treatment, they would play the role of propping. After the

fracturing, two sets of propping systems would be made available: one is the conventional grain size proppant

system in the principal fracture, and the other is the small-grain size proppant or pulverized sand/ceramsite

system in multiple natural fractures.

3) Comprehensive fracture height control technique

The latest advances in recent years mainly include: � Highly viscous gel slugging technique; also, the

conventional single-stage slug has evolved to multi-stage slug, so as to control the fracture height in the

far-wellbore zone; � Fracture height control technique with mixed grain sizes. The small grain size plays the

plugging role at both upper and lower endings of the fracture, while the large grain-size proppant forms the

bridge plugging mainly at locations close to the middle part of the fracture. The combination of small and large

grain sizes could cut off the pressure transfer at different locations of both upper and lower endings of the

fracture. As for the fracture height control technique with multi-stage highly viscous gel slug, the principles are

shown in Figure 18.

Figure 18 Illustration of fracture height control technique with multi-stage highly viscous gel slug

As for the fracture height control with combined grain size proppant, the principle is given in Figure 19.

Generally, the treatment steps include: 2 ~ 3 m3/minute cross-linking fluid (to form the principal fracture; the

volume of pad fluid dependent upon fracture design), 3 ~ 3.5 m3/minute base fluid (carrying mixed grain size) +

displacement volume of 1 wellbore, pumping shut-in for 3 ~ 5 minutes (to allow the proppant to settle down on

the bottom of fracture and form the barrier), continuing the cross-linking fluid and pad fluid (slug injection), and

the principal fracturing treatment.

Figure 19 Illustration of principle of fracture height control with mixed grain size proppant

4. Results: case study of the application of fracturing and acidizing technologies to complex gas fields

Now, let’s place eyes on the application examples of some tight clastic reservoirs, carbonate reservoirs,

volcanic reservoirs, and abnormal HPHT reservoirs, as well as the results attained.

�1�Typical examples for tight clastic reservoirs [4-6]

1) Large-scale fracturing

In China, the large-scale fracturing technology is principally applied to the tight clastic gas reservoirs which

have the following characteristics: the natural fractures don’t develop, the permeability is below 0.1×10-3µm

2,

the sand thickness is above 20 m, the transverse distribution of sand is stable, and the fracture orientation

remains consistent with the favorable sand spreading direction. For the large-scale fracturing, the gist is to

assure the satisfactory shear rheology and low damage of frac fluid for a long period (> 4 hours); normally the

quickly soluble guar gum is used, and frac fluid is continuously blended on the site.

Figure 20 Comparison of results between common fracturing and the Xujiahe large-scale fracturing in Guang’an

of Sichuan

2) Example of zonal fracturing with four-stage packer

Xujiahe E Well in Sichuan may be taken as an example: the target interval for fracturing has a large span

(344 m) and multiple small layers (5 in total), in addition to low porosity (5 ~ 8%), low permeability (<

0.5×10-3µm

2), and low pressure (pore pressure coefficient of 0.8 MPa/100m). Principally, the zonal fracturing

technology with four-stage packer is employed; moreover, gel breaking optimization is considered for each

layer separately, so as to insure that all the layers could be made available with satisfactory propping profile.

Figure 21 Comprehensive curve of zonal fracturing treatment with four-stage packer for Xujiahe E well in

Sichuan

After four-stage packer is employed in Well A, the zonal fracturing time is largely curtailed. In the past, 4

runs of single-layer fracturing normally required 1 month or more; now, the well costs 6 hours and 57 minutes

only. Obviously, both expenses and fluid damage are reduced. For the well, the cumulative consumption of

proppant attains 121.9 m3, the post-frac initial yield reaches 2.3×10

4 m

3/d, and the stable yield arrives at

1.5×104 m

3/d. It is increased by 40% or more to the comparable wells.

3) Example of selective zonal fracturing with seal balls placed in pad fluid

In Shan 1 and He 8 formation, F Well of Changqing Sulige, the perforation span reaches 20 m, 5 m/ 3

intervals are perforated, and the inter-layer stress difference arrives at 4 MPa or so. That is, the stress

conditions are suitable for the fracturing with seal balls placed in pad fluid. As for other reservoir parameters,

see Table 2.

Table 2 Main reservoir parameters of formation Shan 1 and He 8 for F Well in Changqing Sulige

Horizon Small layers

Interval m

Thickness m

Permeability ×10

-3µm

2

Porosity %

Gas saturation %

19 3288.3-3286.8 1.5 2.2 11.5 64.8 Shan 1

17 3283.8-3279.8 4.0 4.1 12.7 70.4

He 8 13 3268.6-3265.3 3.3 3.6 13.7 57.5

After the treatment, the pressure rises apparently; see Figure 22 (the pressure drop prior to ball injection is

resulted from the discontinued injection of liquid nitrogen; nevertheless, the conclusion could be obviously

drawn that the pressure rises after ball injection). As for the post-frac performance, see Figure 23.

Figure 22 Curve of selective fracturing treatment with seal balls placed in pad fluid for F Well in Changqing

Sulige

Figure 23 Gas yield curve after fracturing treatment with seal balls placed in pad fluid for F Well in Changqing

Sulige

As compared with other adjacent wells, this well presents a much noticeable improvement in fracturing

results, i.e., higher by 30% or more. That is, much more layers are successfully fractured during the treatment.

�2�Typical examples of stimulation of carbonate gas reservoirs

1) Example of large-scale acidizing and fracturing with pad fluid for crevice-cavity type carbonate Well G in

Tarim

Whereas crevices and cavities develop in the well, the main stimulation technology involves fracture

detection by pad fluid as well as large-scale acid fracturing, so as to communicate the far-wellbore

crevice-cavity systems. This well has a median burial depth of 5,418 m; in the course of treatment, the

pressure declines by 50 MPa; obviously, a large crevice-cavity system is encountered. The pre-frac yield is

zero, and after the treatment, the daily gas yield is 72.7×104m

3, with the daily crude production at 485 m

3.

2) Example of hydraulic proppant fracturing for karst pore-cavity type carbonate Well H in Tarim

In Well H, the interval for treatment falls within 4,851.1 ~ 4,885.0 m, the formation temperature is 132°C,

and the formation pressure is 55.1 MPa. The proppant volume reaches 30.54 m3. Prior to the fracturing, only a

small volume of natural gas has been produced; and, after the treatment, the gas and crude yields are 64,654

m3/d and 148.75 m

3/d, respectively.

3) Example of acid fracturing with surface cross-linked acid for creviced carbonate Well I in Tarim

For Well I, the target interval ranges within 5,595 ~ 5,603 m, with the formation temperature at 141°C and

formation pressure at 67.65 MPa; the treatment fluids are 215 m3 pad fluid + 170 m

3 surface cross-linked acid.

The pre-frac yield is nil, and after the acid fracturing, the gas and crude yields are 11,084 m3/d and 15 m

3/d,

respectively.

Figure 24 Comprehensive curve of acidizing and fracturing treatment with surface cross-linked acid for creviced

carbonate Well I in Tarim

4) Example of proppant fracturing with surface cross-linked acid for carbonate Well J in Tarim

For this well, the target interval ranges within 5,529 ~ 5,550 m; for the first time, true proppant fracturing with

surface cross-linked acid is successful in the formation with the hole depth exceeding 5,000 m and

temperature above 143°C; the maximum proppant concentration attains 463 kg/m3, and the proppant

consumption reaches 36.2 m3, in which 22m

3 is completely carried by the cross-linking acid.

Figure 25 Comprehensive curve of sand fracturing treatment with surface cross-linked acid for carbonate Well J

in Tarim

Note: Stage 1: Pump pre-treatment Acid 10m3 with low flow rate;

Stage 2: Pump linear gum 27m3 with Low flow rate;

Stage 3: Pad fluid 386m3;

Stage 4: Slurry fluid 189m3;

Stage 5: Displacing fluid 26.8 m3;

Stage 6: Pressure decline test.

�3�Typical examples for stimulation of volcanic gas reservoirs

1) Example of large-scale fracturing for Well K of volcanic gas reservoirs in Daqing Songliao Basin

In the well, the interval for treatment ranges within 2,890 ~ 2,898 m, where natural fractures develop and

the high-angle fractures coexist with those low-angle ones and network ones. The employment of, for example,

mini-frac test, proppant slugging, real-time control of net fracture pressure, etc., has insured the propagation of

principal fracture and the smooth execution of the large-scale fracturing.

Figure 26 Comprehensive curve of large-scale fracturing treatment for Well K of volcanic reservoirs in Daqing

Songliao Basin

After the two runs of injection of pulverized sand, surface pressure declines noticeably. In the late phase of

treatment, 20% proppant to liquid ratio is maintained until the bottom hole is reached, and the pressure rises

rapidly. According to the analysis, since there are multiple fractures within the formation, the filter loss is high

and proppant screen-out occurs at the front edge of fracture; when the flow rate declines to 4.6 m3/minute, the

pressure is stabilized; the maximum proppant to liquid ratio is 25.0%; after the blending of 102.0 m3

of

ceramsite, the mean proppant to liquid ratio is 21.0%. Prior to the fracturing, a minor quantity of gas is

produced; and, after the treatment, the daily gas production attains 10.2×104 m

3, with the open-flow capacity at

28.4×104m

3.

�4�Typical examples of stimulation of abnormal HPHT gas reservoirs [7-10]

1) Example of fracturing for Well L in high-stress formations of Tarim

In this well, the target interval for treatment falls within 5,725 ~ 5,783 m, with the formation temperature at

123°C, formation pressure at 90.6 MPa, and pressure coefficient at 1.66 MPa/100m; in addition, natural

fractures develop. Heavier frac fluid (density at 1.15 g/cm3) is employed to reduce the treatment pressure by 8

MPa; proppant slug is used for the purposes of grinding and reduction of filter loss; the small grain size

proppant is used (30/50 mesh). During treatment, the pumping pressure reaches 90 MPa (max. pressure

resistance of equipment: 103 MPa), with the flow rate at 0.5 ~ 3.4 m3/minute, and the proppant blending

volume at 28.5 m3. Prior to the fracturing, the gas yield is 10.4×10

4 m

3/d; in contrast, the post-frac one is

30.7×104 m

3/d.

2) Example of acid fracturing with heavier acid for Well M in high-stress formations of Tarim

In this well, the perforated intervals are 6,354 ~ 6,363 m and 6,380 ~ 6,389 m. Heavier acid is employed,

with the density up to 1.335 g/cm3, effectively reducing the treatment pressure by 15 MPa. Normally, the

treatment pressure ranges within 90 ~ 98 MPa, 100.1 MPa to the maximum. After the acid fracturing, the gas

and condensate oil yields are 22.4×104 m

3/d and 94.78 t/d, respectively, given the reservoir pressure of 73.5

MPa.

3) Example of acid fracturing for high-temperature Well N in Tarim

The hole depth ranges within 6,573 ~ 6,697 m, featuring high temperature (165°C), abnormal high pressure

(pressure coefficient > 2.0 MPa/100m), thick layer, noticeable difference amongst layers, and developed

natural fractures. Injection is conducted with 4-1/2” tubing; highly viscous acid is used for temporarily plugging

up the natural fractures, and gelled acid used for reducing the frictional resistance, in addition to actualizing the

deep acid etched goal. For the treatment, the pumping pressure is 75.5 ~ 99.3 MPa, and the flow rate is 0.5 ~

3.2 m3/minute. Prior to the treatment, the gas yield is 19.8×10

4 m

3/d, and, after acid fracturing, it rises to

46.6×104 m

3/d.

4) Example of fracturing with low-concentration carboxymethyl guar gum (CMHPG) for Well O in the extra

high temperature formation of Jilin

In this well, the reservoir depth falls within 5,217 ~ 5,224 m, with the reservoir temperature at 183°C. The

independently developed, world edge-cutting carboxymethyl guar gum frac fluid is employed; the content of

residues is low (294 mg/L); the consumption of densifier is reduced to 0.6%, 25% lower as compared with the

conventional guar gum; and the viscosity ranges between 80 and 110 mPa.S. The fracturing treatment time is

long, i.e., 4.5 hours; 55m3 proppant is added successfully. After fracturing, the daily gas and water productions

are 2.4×104m

3 and 100 m

3, respectively.

5. Conclusion and suggestions [11]

For the fracturing and acidizing conducted to complex gas fields, hard efforts have been made in following

up the latest developments of the foreign countries; more importantly, specific researches and improvements

have been unfolded in consideration of the actualities of different types of reservoirs. Up to date, a complete

package of fracturing and acidizing technologies has been basically made available; nevertheless, certain

weak points exist, which need to be settled in the next step. Concretely,

�1�In China, the complex gas fields mainly involve three types, namely, tight clastic, carbonate, and

volcanic, which are distributed in such basins as Ordos, Sichuan, Tarim and Songliao. Thanks to the relatively

concentrated distribution in geology, it is favorable for presenting the mainstream stimulation technologies

suitable for each region. For instance, the large-scale fracturing and zonal fracturing technologies for tight

clastic reservoirs (four-stage packer, selective zonal fracturing with seal balls placed in pad fluid); the acid

fracturing technology with surface cross-linked acid, the hydraulic proppant fracturing technology, and the

proppant fracturing technology with surface cross-linked acid for the carbonate reservoirs; and the

large-scale fracturing technology for volcanic reservoirs.

�2�Abnormal HPHT reservoirs may be seen in each of the three types mentioned above. For them, the

main technologies involve heavier frac fluid and acidizing fluid.

�3�Mainly speaking, the in-situ matching techniques include the multi-stage linear gum proppant slugging,

the principal fracture propagation control with mixed grain sizes and the control of net pressure, the fracture

height control with multi-stage highly viscous gel slug, and the fracture control with mixed grain sizes.

�4�Through in-situ test and popularization, such technologies have uplifted the success rate and efficiency

of the fracturing and acidizing treatment conducted to the complex gas fields in China, largely propelling the

local gas exploration and development process.

�5�For these gas fields, the stimulation technologies shall seek for advances in the future mainly in the

following:

1) Reservoir assessment shall place eyes on precise description of natural fractures and random modeling

of parametric field;

2) Experimental technologies shall emphasize on the 3D extended physical modeling for large (75 mm × 75

× 90 mm or higher) fractures, long-term gas conductivity under non-Darcy flow, long-term fluid conductivity

under multiple-phase flow, physical modeling of proppant transport profile, and so on;

3) In view of fluids, the focus shall lie in the R&D of low-damage heavier frac fluid and acidizing fluid,

high-temperature resistant (> 200°C) frac fluid and acidizing fluid, high-temperature VES fluid (frac fluid and

acidizing fluid), VES self-diverting acid, micro emulsified acid, micro emulsified frac fluid, etc.;

4) In terms of proppant, emphasis shall be placed on the extra-low density (1.05 ~ 1.25 g/cm3) proppant,

film-covered proppant, and short-fibre proppant;

5) As for the stimulation technologies, the eyes shall be placed onto the coiled tubing zonal fracturing and

acidizing, the multistage fracturing and acidizing for complex holes (e.g., horizontal wells, pinnate wells), the

fracture diagnostic technique in the case of multiple fissures, etc.

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