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Abstract

Since CO₂ Stimulation in Horizontal Wells can avoid the problem of steam flooding, clay swelling, and sand production, it has been carried out in many fields. To improve the research on the controlling factors and their influence and establish a specific reservoir selecting method, this paper founded the components and geology model according to typical heavy oil reservoirs firstly. Comparing with pilot test, the theoretical model result could give expression to the characteristic of large water ratio descend rang, long period of validity, and high rounds effectiveness. Secondly, this study designed simulation scheme including factors of geology, development, and stimulation technology, to filter the controlling factors of the oil incremental and well reopened water cut and describe their influence. Based on it, we proposed a quick filter criterion to choose heavy oil reservoirs for CO₂ stimulation.

1. Introduction

The technology of horizontal wells has applied in many viscous oil reservoirs, with process of steam stimulation and steam drives commonly. However, injected water and/or steam leads to not only clay swelling and sand production but also fast oil production decrease in high rounds stimulation, especially in water-sensitive reservoirs. The horizontal well CO₂ stimulation has been used in enhanced oil recovery [1 –4], high water cut reservoirs, heterogeneous reservoirs, and viscous oil not fit for thermal recovery since 1970s. Its mechanism include reducing oil viscosity, expanding oil volume, promoting solution-gas-drive, decreasing interfacial tension, acidizing, improving mobility ratio and density ratio, and increasing sweep efficiency. The result of this technology in Pisticci fields is worse than in Paradis, Trinidad and Tobago field [5 –7], because of high gas-oil ratio [8].

Since 1970s, there is tremendous research on optimizing cyclic CO₂ injection volume, injection rate, soaking time, production velocity of vertical well CO₂ stimulation by laboratory experiment, and simulation research [9, 10], but little information is available on geology factors including formation dip, Heterogeneous degree, development factors including initial water cut, wellbore condition, and location of horizontal branch.

To solve this problem, using theoretical model method, this paper improves the study on controlling factors in horizontal well CO₂ stimulation of heavy oil, rating the sensitive degree of geology, development, and technological parameters, and establishing viscous oil reservoir selecting method for CO₂ stimulation.

2. Dynamic Modeling

2.1. Component Modeling

To facilitate the numerical simulation, the typical heavy oil components were incorporated into nine pseudo components according to the principle of property similarity. Based on matching the fluid properties and the result of expansion experiment, we obtained the ratio of nine components which reflects the real formation fluid phase state (Table 1). In addition, the corresponding underground oil viscosity is 87 cp, oil density is 0.992 g/cm³, bubbling pressure is 5.9 MPa and initial gas oil ratio is 21 m³/m³. The PVT data is calculated by PR equation of state.

Table 1:

Components of pseudocomponent.

Pseudocomponent	CO₂	C1 + N₂	C2	C3	C4	C5 + 6	C7 +	C11 +	C29 +

Components (mol%)	1.167	19.647	1.017	0.425	0.447	6.748	11.044	9.628	49.877

2.2. Geology Modeling

We established a geological model of horizontal well CO₂ stimulation, whose plane size is 700 m by 200 m; the grid plane size is 10 m by 10 m. Typically, horizontal well area grid size is 5 m by 5 m (Figure 1); the model thickness was divided into 11 layers, where the 150 m horizontal branch was located in layer 3. The average porosity is 0.26; the average permeability is 30 × 10⁻³ μm².

Figure 1:

Geology model.

2.3. Simulation of Character in Pilot Test

The horizontal well CO₂ stimulation pilot test was carried out in JD oil field (Table 2). The numerical methods used in the simulations are adaptive implicit method.

Table 2:

Pilot test area properties.

Factors	Pilot test area

Depth (m)	1750~1850
Formation dip (°)	1~4
Formation thickness (m)	1.3~24
Porosity (f)	0.26
Permeability (10⁻³ μm²)	928~1281
Oil viscosity (mPa·s)	90.34
Oil density (kg/m³)	910.6

CO₂ stimulation was carried out in a total of 45 horizontal wells, of which geology, development factors are different, such as interlayer, thickness, initial water cut, and horizontal branch position. Different injection process parameters, such as cyclic CO₂ injection amount, injection rate, soaking time, and production velocity, were designed for different horizontal well, and the maximum cycle oil increment is up to 2000 t. The CO₂ stimulation dynamic characteristics can be summarized as follows.

(1) The water cut is low when the CO₂ stimulation well is reopened. Before the horizontal well CO₂ huff and puff, the average of water cut is 94%, as the water cut is 43%, on average, after CO₂ stimulation. Some of the wells’ water cut specially could become 2% from 99%, showing that the CO₂ can remove the water near the wellbore, and density difference between oil and CO₂ makes oil full of this part.

As Figure 2 shows, the initial water cut of well W1 is 15%. When the water cut reached 97% on July 9, 2011, 325 t CO₂ were injected during 4 days. After stuffy well of 20 days, water cut became 1% and gradually rose to 38% a month later. After five months, water cut was up to 97% again, and CO₂ stimulation validity period is over.

Figure 2:

Low well reopened water cut by CO₂ stimulation.

(2) CO₂ stimulation validity period last for more than 3 months. The statistics of 45 oilfield CO₂ stimulation pilot test results show that average of validity period lasts for 250 days. The reason might be that water flow resistance and swept volume is enlarged because of the making of foam in low pressure area near wellbore.

As Figure 3 shows, the initial water cut of well W2 is 28%. When the water cut reached 92% on October 18, 2011 because of high production rate, 300 t CO₂ were injected during 3 days. After stuffy well of 20 days, water cut became 18%. After seven months, water cut was up to 92% again, and CO₂ stimulation validity period lasts for 227 days.

Figure 3:

Validity period last for more than 3 months.

(3) Multicycle CO₂ stimulation is still effective. Nine members of the 45 horizontal wells have carried out two rounds of CO₂ stimulation. In spite of the fact that increased oil production is reducing with the increase of throughput rounds, the maximum oil production of second round is up to 1000 t.

As Figure 4 shows, the initial water cut of well W3, located in the peak of formation, is 4%. Because of high water cut, the first round CO₂ stimulation was implemented in October, 2008. The water cut became 17% and CO₂ stimulation validity period lasts for 250 days, which increased oil production 691 t. The second round CO₂ stimulation was implemented in June, 2007. The water cut became 14% and CO₂ stimulation validity period lasts for 228 days, which increased oil production 1000 t.

Figure 4:

Effective in high round.

Typical theoretical model's 3 times CO₂ stimulation parameters are designed as injecting CO₂ with rate of 100 t/d for 3 days when water cut rises to 99%, then shut well for 30 days. When the well is reopened, the water cut is 20%, 19%, and 20%, respectively; the period of validity is in more than one year; the increased amount of oil in 2nd and 3rd round stimulation is, respectively, 442 m³ and 277 m³, inosculates with the dynamic characteristics of pilot test (Figure 5). Analysis of CO₂ distribution and water saturation (Figures 6, 7, and 8), it shows that the typical model can simulate the phenomenon of CO₂ driving water near wellbore and improving microscopic oil displacement effect. In conclusion, typical theoretical model can reflect the actual effect of heavy oil reservoir horizontal well CO₂ stimulation.

Figure 5:

Result of typical theoretical model.

Figure 6:

Water saturation before the 2nd CO₂ injection.

Figure 7:

Water saturation after the 2nd CO₂ injection.

Figure 8:

CO₂ distribution after the 2nd CO₂ injection.

2.4. Simulation Project Design

The result of horizontal well CO₂ stimulation in heavy oil reservoirs is affected by the geology factors, such as formation dip, net thickness, rhythmic pattern, heterogeneity, and interlayer location; the development factors, such as wellbore condition, initial water cut, horizontal branch location, and production of adjoining well in high region; and the technology factors, such as stimulation time (water cut), injection CO₂ volume, injection rate, soaking time, and production rate. Enlarge the typical value distribution of viscous oil reservoirs properly, and simulation project is designed with 335 instances (Table 3). Lorentz coefficient especially is used to quantitate vertical heterogeneity (Figure 9).

Table 3:

Simulation project design.

No.	Factors	Values	Analysis	Default values

1	Formation dip (°)	3, 6, 10	Single-factor	3
2	Formation thickness (m)	1.1, 3.3, 6.6, 9.9, 13.2	Single-factor	6.6
3	Rhythmic pattern	positive, negative	Single-factor	Positive
4	Heterogeneity (Lorenz coefficient)	0, 0.2, 0.5, 0.8	Single-factor	0.5
5	Interlayer location	No interlayer, the middle, the bottom	Exhaustive method	No interlayer
6	Length of water discharge stage	Spot, one-third of the branch, all branch		Spot
7	Location of water discharge stage	Near heel, toe, between heel and toe, whole stage		Heel
8	Heterogeneous degrees of water discharge stage	1, 5, 15, 50		1
10	Initial water cut (%)	0, 28		0
9	Injection timing	Water cut beyond 20%, 60%, 95%	Exhaustive method	95%
11	Location of horizontal branch	In the top, upper-middle, and lower-middle	Exhaustive method	top
12	CO₂ injection volume (sm³)	100000, 150000, 250000, 400000	Single-factor	150000
13	CO₂ injection rate (sm³/d)	20000, 30000, 50000, 100000	Single-factor	50000
14	Soaking time (d)	7, 15, 30, 60	Single-factor	30
15	Production rate (rm³/d)	5, 10, 20, 40	Single-factor	10
16	Distance to adjoining well in higher position	35 m, 65 m, 85 m, no adjoining well	Single-factor	No adjoining well
17	Production rate of adjoining well in higher position (rm³/d)	0, 150, 250, 350	Single-factor	0

Figure 9:

Map of Lorenz curve.

3. Controlling Factors Selecting

The controlling factors of CO₂ stimulation in heavy oil is selected by analyzing the change law of well reopened water cut and oil increment, which is defined as production oil volume during validity periods.

3.1. Controlling Factors for Oil Increment

Since oil increment is positive correlation with the result of CO₂ stimulation, defining the standard as the difference and ratio of the maximum and minimum oil increment, controlling factors were selected (Tables 4 and 5). Specific standard is as follows:

not sensitive: no influence to oil increment;

weak sensitive: has influence to oil increment and the difference below 100 m³ or the ratio below 1.4;

midterm sensitive: has influence to oil increment and the difference beyond 100 m³ and the ratio beyond 1.4;

strong sensitive: has influence to oil increment and the difference beyond 200 m³ and the ratio beyond 2.

Table 4:

Controlling factors for oil increment.

Factors	The sensitive	The max./m³	The min./m³	The difference	The ratio

Formation dip	Weak	501	478	23	1.05
Interlayer location	Weak	494	453	42	1.09
Formation thickness	Midterm	469	332	137	1.41
Rhythmic pattern	Weak	494	467	27	1.06
Heterogeneity (Lorentz coefficient)	Strong	521	56	465	9.36
Initial water cut	Midterm	489	462	27	1.06
Length of water discharge stage	Weak	482	466	15	1.03
Location of water discharge stage	Weak	479	466	13	1.03
Heterogeneous degrees of water discharge stage	Weak	483	469	13	1.03
Location of horizontal branch	Weak	508	446	62	1.14
Injection timing	Strong	470	117	352	4.00
CO₂ injection volume	Strong	1088	294	795	3.70
CO₂ injection rate	Weak	473	465	8	1.02
Soaking time	Weak	497	444	53	1.12
Production rate	Weak	484	469	16	1.03
Distance to adjoining well in higher position	Strong	469	10	458	45.49
Production rate of adjoining well in higher position	Strong	469	3	465	151.15

Table 5:

Oil increment change law.

Factors	Regularity

Formation dip	Positive correlation.
Interlayer location	Descending order is in the bottom, no interlayer, in the middle when initial water cut is 0; descending order is in the middle, in the bottom, no interlayer when initial water cut is 28%.
Formation thickness	Positive correlation when below 6.6 m, then negative correlation.
Rhythmic pattern	Negative is better.
Heterogeneity (Lorentz coefficient)	Negative correlation.
Initial water cut	Positive correlation when interlayer in the middle; negative correlation in the remaining cases.
Length of Water Discharge Stage	Negative correlation.
Location of Water Discharge Stage	Not sensitive when the length is spot or one-third.
Heterogeneous degrees of Water Discharge Stage	Negative correlation.
Location of horizontal branch	Descending order is in the lower-middle, the upper-middle, and the top.
Injection timing	Positive correlation.
CO₂ injection volume	Positive correlation.
CO₂ injection rate	Positive correlation.
Soaking time	Positive correlation.
Production rate	Positive correlation.
Distance to adjoining well in higher position	Positive correlation.
Production rate of adjoining well in higher position	Negative correlation.

Above all, the controlling factors for oil increment are formation rhythmic pattern, stimulation time, injection CO₂ volume, and adjoining well in high region. It shows the following.

Horizontal well CO₂ stimulation of viscous oil has great potential in popularizing in oil fields as its controlling factor is in low number.

The foundation and precondition to CO₂ stimulation successful is reasonable parameter of CO₂ injection 10 and oil production.

3.2. Controlling Factors for Well Reopened Water Cut

Since well reopened water cut has effect on the result of CO₂ stimulation, defining the standard as the difference and ratio of the maximum and minimum well reopened water cut, controlling factors were selected (Tables 6 and 7). Specific standard is as follows:

not sensitive: no influence to oil increment;

weak sensitive: has influence to the water cut and the difference below 10% and the ratio below 10;

midterm sensitive: has influence to the water cut and the difference below 10% and the ratio beyond 10;

strong sensitive: has influence to the water cut and the difference beyond 20%.

Table 6:

Controlling factors for well reopened water cut.

Factors	The Sensitive	The max./m³	The min./m³	The difference	The ratio

Formation dip	Weak	3.2	3	0.2	1.05
Interlayer location	Weak	4.3	2.3	2	1.87
Formation thickness	Midterm	5.2	0.4	4.7	11.74
Rhythmic pattern	Midterm	5.5	0.4	5.1	13.75
Heterogeneity (Lorentz coefficient)	Strong	20.2	0	20.2	Infinity
Initial water cut	Midterm	3.3	2.7	0.6	1.22
Length of water discharge stage	Weak	4.2	1.6	2.6	2.63
Location of water discharge stage	Weak	3.1	0.1	3	31.00
Heterogeneous degrees of water discharge stage	Weak	5.2	2.7	2.5	1.93
Location of horizontal branch	Midterm	5.5	0.1	5.4	55.00
Injection timing	Weak	1.3	0	1.3	Infinity
CO₂ injection volume	Weak	7.5	2.3	5.2	3.30
CO₂ injection rate	Weak	3.3	2.3	0.9	1.40
Soaking time	Weak	4.6	1.7	2.9	2.75
Production rate	Strong	26.7	2.6	24.2	10.44
Distance to adjoining well in higher position	Strong	76.2	2.8	73.4	26.75
Production rate of adjoining well in higher position	Strong	89.5	2.8	86.7	31.42

Table 7:

Well reopened water cut change law.

Factors	Regularity

Formation dip	Positive correlation.
Interlayer location	In the middle with the highest water cut.
Formation thickness	Positive correlation.
Rhythmic pattern	Negative with lower water cut when horizontal branch is in the upper-middle or top; positive with lower water cut when horizontal branch is in the lower-middle.
Heterogeneity (Lorentz coefficient)	Positive correlation.
Initial water cut	Positive correlation.
Length of water discharge stage	Negative correlation.
Location of water discharge stage	Not sensitive when the length is spot or one-third.
Heterogeneous degrees of water discharge stage	Negative correlation.
Location of horizontal branch	In the positive formation, the upper-middle with highest water cut (injection when water cut beyond 95%), the upper-middle with lowest water cut (injection when water cut below 95%). In the negative formation, the lower horizontal branch is, the higher water cut is.
Injection timing	Positive correlation.
CO₂ injection volume	Negative correlation.
CO₂ injection rate	Positive correlation.
Soaking time	Negative correlation.
Production rate	Positive correlation.
Distance to adjoining well in higher position	Negative correlation.
Production rate of adjoining well in higher position	Positive correlation.

Above all, the controlling factors for well reopened water cut are formation rhythmic pattern, production rate, and adjoining well in high region, similar to oil increment. It shows that the result of CO₂ stimulation is determined by reservoirs characteristics, adjoining wells and parameter of CO₂ injection.

4. Reservoir Selecting Method

By previous work on CO₂ stimulation field test, reservoirs disagree with CO₂ stimulation when we have the following situations.

Fractures are distributed near wellbore.

A high production rate adjoining horizontal well is located in higher position.

Horizontal branch is located in water layer, suggesting water plugging before CO₂ injection.

Initial water cut is beyond 90%, suggesting water plugging before CO₂ injection.

Based on the result of Chapter 3, we described a reservoir selecting method for CO₂ stimulation in viscous oil preliminary (Table 8), and this method has been applied on pilot test.

Table 8:

Reservoir selecting method.

Factors	Selecting standard	Sensitivity

Distance to adjoining well in higher position Production rate of adjoining well in higher position	Disagrees with CO₂ stimulation.
Initial water cut	Below 95%.	Midterm
Heterogeneous degrees of water discharge stage	Below 50.	Weak
Injection timing	Beyond 60%, beyond 95% is suggested.	Strong
Heterogeneity	Below 0.5.	Strong
Formation thickness	Suggesting 7 m.	Midterm
Formation dip	Beyond 3°.	Weak
Interlayer location	Suggesting in the middle.	Weak
Rhythmic pattern	Negative.	Weak
Length of water discharge stage	Short is better.	Weak
Location of horizontal branch	Suggesting in the lower-middle.	Weak

5. Conclusions

The typical theoretical model can reflect the actual effect of heavy oil reservoir horizontal well CO₂ stimulation.

The controlling factors for oil increment and well reopened water cut are formation rhythmic pattern, stimulation time, injection CO₂ volume, and adjoining well in high region.

The reservoir selecting method was established including 12 criteria.

Conflict of Interests

The authors declare that there is no conflict of interests regarding the publication of this paper.

Footnotes

Acknowledgment

This work was supported by Major National S&T Projects (2011ZX05009, 2011ZX05054, and 2011ZX05011).

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