Introduction
Tight oil represents a significant percentage of unconventional resources throughout the world and play increasingly important roles in the energy industry. In China, abundant tight oil resources have been discovered in some large petroliferous basins, such as the Ordos Basin, Sichuan Basin, Songliao Basin, and Qaidam Basin[1,2,3]. Drawing on overseas volume fracturing technique, many oil and gas fields have explored and tested volume fracturing in tight oil reservoirs, with good stimulation results achieved[4,5,6,7]. However, tight oil reservoirs have poor physical properties, making some horizontal wells fail to form an injection-production pattern for formation energy supplement. In addition, with strong stress- sensitivity, hydraulic fractures are likely to close[8,9,10,11], resulting in rapid production decline and short stable production period, adversely affecting the development effect. To restore or increase productivity of this kind of well, refracturing technique is the main measure [12,13,14,15].
A lot of studies and practices on refracturing have been conducted overseas, involving primarily well selection for refracturing[16,17,18,19,20], refracturing design[21,22,23,24], and refracturing effect evaluation[25,26,27]. Candidate well selection is critical for defining optimal timing of refracturing. For tight oil reservoirs, volume fracturing in horizontal well corresponds to very different parameters such as reservoir physical properties, initial completion efficiency, and production performance from conventional hydraulic fracturing. The factors are complicated and correlated with each other, and have different effects on refracturing, making it very difficult to select the refracturing timing. Furthermore, there have been few studies on how to systematically determine the optimal timing of horizontal well refracturing.
In this study, the analytical hierarchy process (AHP) was used together with the unique parameters of volume fracturing horizontal wells in the pilot area of tight oil reservoirs in the Songliao Basin to determine the parameter values of the ideal refracturing well. The fuzzy clustering method was adopted to prioritize and rank the refracturing potentials of wells, and numerical simulation method was employed to further evaluate such potentials. Then, refracturing productivity forecasting model considering the stress-sensitive effect at different production times was established to select the refracturing method and timing. The breakdown pressure forecasting model was applied to calculate the formation breakdown pressure in different positions of the horizontal section at the optimal timing, and to work out the times of temporary plugging reorientation and the dosage of temporary plugging agents. In this way, the development effect of tight oil reservoirs can be effectively improved.
1. Overview of the study area
1.1. Geologic characteristics
Tight oil reservoirs in the Songliao Basin are deposits of semi-deep to deep lake facies interbedded with delta front subfacies and fluvial facies. Mainly distributed in the Gaotaizi and Fuyu oil zones in the Lower Cretaceous Qingshankou Formation, they are wide in area and huge in resource potential. Strongly heterogeneous, they aren’t concentrated in longitudinal direction and continuous in lateral, and are small in single sweet spot, poor in continuity, greatly variable in physical properties and oil-bearing property[3]. Moreover, they are tight, with a porosity of 5-12% (11.5% on average) and permeability of (0.1-10.5)×10-3 μm2 (1.25×10-3 μm2 on average). They have an average oil saturation of 52%, a thickness of less than 5 m in single layer or 5-15 m cumulatively, a burial depth of 1 700-2 450 m, a formation pressure gradient of 0.049 6-0.053 1 °C/m (0.0518 °C/m on average), and an average pressure of 17.5 MPa. The crude oils in them have a viscosity of 1.62-8.05 mPa·s (6.36 mPa·s on average).
1.2. The Development
Due to poor physical properties and low oil saturation, the tight oil reservoirs have low flowing capability, and can hardly meet the commercial productivity through conventional fracturing. For example, of 180 exploratory wells in the Gaotaizi oil zone, the vertical wells have a daily oil production after hydraulic fracturing of 0.16 to 7.20 tons, and 90% of the wells cannot reach the commercial oil and gas production. In line with the geological characteristics of such reservoirs, staged and clustered horizontal well volume fracturing was adopted in the study block, achieving an average daily oil production of 21.5 tons. In the later stage of development, as physical properties of the reservoirs turned worse, hydraulic fractures induced during the initial fracturing failed, the reservoirs were insufficiently stimulated, and most wells failed to get energy supplement from conventional water injection through effective injection-production pattern, the average oil production has dropped to 3.2 tons currently, representing poor development effect. Refracturing is the major way used to increase single-well production rate and enhance ultimate recovery in this block, and the timing of refracturing is crucial to the stimulation effect.
2. Refracturing productivity forecasting model
2.1. Selection of factors affecting refracturing timing
The appraisal factors of volume fracturing horizontal well which influence the refracturing effect were divided into two levels using analytic hierarchy process. Factors in the main criterion level include ‘reservoir physical properties’, ‘initial completion efficiency’, and ‘production performance’ (Table 1). The ideal refracturing well with the highest refracturing potential was sorted out, and the Euclidean distance and similarity coefficient of the candidate well with the ideal well were calculated. The smaller the Euclidean distance and the bigger the similarity coefficient, the higher the similarity between the candidate well and ideal refracturing well is. Fuzzy clustering was applied to determine the classification threshold and the priority of the refracturing wells. The value of ideal refracturing well parameters were defined according to the distribution range of candidate well parameters including reservoir physical properties, initial completion efficiency and production performance. According to large amounts of production data and their correlation with productivity, the maximum value of the parameters positively correlated with fracturing effect and the minimum value of parameters negatively correlated with fracturing effect were taken as the ideal ones. Specifically, the minimum value of initial fracturing parameters, ‘number of clusters’, ‘average fracturing fluid volume per cluster’, and ‘average proppant volume per cluster’ were taken, which mean the initial fracturing was not sufficient. Based on the candidate well parameters, a fuzzy matrix was established and normalized. Then, Euclidean distance and similarity coefficient between the candidate well and ideal well were calculated using Eq. (1) and Eq. (2) to select the wells with the highest refracturing potentials.
Table 1 Parameter values for an ideal refracturing well.
| Main criterion level | Sub criterion level | Distribution range of candidate wells | Parameter value of ideal refracturing well |
|---|---|---|---|
| Reservoir physical properties | Oil-bearing sandstone length/m | 240-1 880 | 1 880 |
| Net pay thickness/m | 2.3-6.3 | 6.3 | |
| Porosity/% | 8.9-11.6 | 11.6 | |
| Permeability/10-3 μm2 | 0.44-2.31 | 2.31 | |
| Oil saturation/% | 39-56 | 56 | |
| Initial completion efficiency | Number of fracturing clusters | 12-32 | 12 |
| Fracture spacing/m | 50-98 | 98 | |
| Fracturing fluid volume per cluster/m3 | 342-980 | 342 | |
| Proppant volume per cluster/m3 | 11-65 | 11 | |
| Production performance | Current formation pressure/MPa | 10.8-17.4 | 17.4 |
Sixteen volume fracturing horizontal wells in the block concerned with an average daily oil production of 3.2 t were selected to establish the ideal refracturing well (Table 1). The Euclidean distance and similarity coefficient between them and the ideal well were calculated to determine the classification threshold and the priority of the refracturing wells. The results are shown in Figs. 1 and 2. The figures show candidate well P10 has the smallest Euclidean distance and largest similarity coefficient, indicating that it is the one closest to the ideal refracturing well. Similarly, based on the Euclidean distance values, the candidate wells were divided into three grades, the gradeⅠwells with Euclidean distance of 0.35- 0.45 have the highest refracturing potentials, the grade II wells with Euclidean distance of 0.60-0.75 take the second place, and the grade III wells with Euclidean distance of 0.85-0.90 are lowest in refracturing potential. Wells of the same grade have similar refracturing potential. The way enables quick selection of refracturing candidate wells.
Fig. 1.
Fig. 1.
Classification of refracturing potential of candidate wells.
Fig. 2.
Fig. 2.
Classification threshold and ranking of candidate well refracturing potential.
2.2. Numerical model establishment and verification
After the well with the highest refracturing potential was selected, a numerical model of reservoir considering the stress sensitive effect was established by using the ECLIPSE simulator. The model was 1 800 m×1 000 m×3.5 m in size and had 18 000 grids with grid spacing of 10 m×10 m×3.5 m. Table 2 shows the basic parameters of the model. The fracture parameters were obtained through inversion using the net pressure fitting method and then input to the numerical model using the local grid refinement method. Among these parameters, the fracture half-length was 100-354 m and the conductivity of the primary fractures was 18.6-35.4 μm2·cm, which vary greatly across all fracturing intervals. In the initial fracturing, the designed fracture half-length and conductivity of initial fracturing were 300 m and 30 μm2·cm respectively, suggesting that some hydraulic fractures failed to effectively communicate the reservoir to provide flow pathways, which significantly affected the actual productivity.
Table 2 Basic parameters of the reservoir model.
| Parameter | Value | Parameter | Value |
|---|---|---|---|
| Reservoir depth | 1 760 m | Formation oil volume factor | 1.12 |
| Net pay thickness | 3.5 m | Length of horizontal section | 1 480 m |
| Formation pressure | 19.5 MPa | Number of stages | 10 |
| Average Porosity | 9.5% | Number of clusters | 22 |
| Average permeability | 1.09× 10-3 μm2 | Average cluster spacing | 80 m |
| Initial oil saturation | 46% | Designed fracture half-length | 300 m |
| Formation oil viscosity | 7.02 mPa•s | Designed fracture conductivity | 30 μm2•cm |
According to the production data of the horizontal well after initial fracturing, history matching was conducted to verify the model. The production performance of the horizontal well with and without stress sensitivity considered were simulated. Figs. 3 and 4 show the matching results.
Fig. 3.
Fig. 3.
Daily oil production history maching curve.
Fig. 4.
Fig. 4.
Cumulative oil production history maching curve.
From Figs. 3 and 4, we can see that the daily oil production and cumulative oil production with and without stress sensitivity considered in the initial stage of development have little differences, but the stress-sensitive effect becomes stronger as the production goes on. For the model without stress-sensitive effect considered, both the cumulative oil production and daily oil production in the middle and later stages of development are much higher than the actual values, and the cumulative oil production has a relative error of 13.1%. For the model with stress-sensitive effect considered, the initial fracturing production simulation results are consistent with the actual cumulative oil production and daily oil production, and conform to actual production performance, with a relative error of only 1.8%, thus verifying that the model is correct.
The remaining oil distribution (Fig. 5) and formation pressure distribution (Fig. 6) were obtained through history matching. The results show that crude oil produced is around fractures, and remaining oil is mainly distributed between fractures and in the distal end of fractures. In addition, the initial fracturing is insufficient and a large volume of remaining oil in the distal end of fractures has not been recovered, with a staged recovery efficiency of only 3.1%. Therefore, a great remaining potential can be expected. The current average formation pressure is 15.8 MPa and the formation pressure retaining degree is 81.3%, which provides energy basis for refracturing.
Fig. 5.
Fig. 5.
Remaining oil distribution.
Fig. 6.
Fig. 6.
Formation pressure distribution.
Based on the history matching, the ECLIPSE restarting function was used to extract the oil saturation field and formation pressure field from the initial fracturing to the time before refracturing. Then, a refracturing productivity forecasting model was established to predict the stimulation effect of refracturing methods at different timings.
3. Optimization of refracturing timing
3.1. Selection of refracturing
Four refracturing methods were proposed based on the hydraulic fracture parameters and remaining oil distribution after initial fracturing: refracturing of the preexisting fractures, preexisting fracture extension, inter-fracture treatment, and temporary plugging and diverting inside fractures (Fig. 7). The aims were to connect more remaining oil zones and increase production by restoring the conductivity of preexisting fractures and adding new fractures. In the refracturing productivity forecasting model, seven fracturing clusters were designed for each of the four methods and the designed parameters were: fracture half-length of 300 m, conductivity of 30 μm2·cm, stable bottom-hole flowing pressure of 8 MPa, and simulated production period of 5 years. The stimulation effects of the four methods were compared (Fig. 8, Fig. 9, and Table 3).
Fig. 7.
Fig. 7.
Classification of refracturing methods.
Fig. 8.
Fig. 8.
Comparison of daily oil production of different refracturing methods.
Fig. 9.
Fig. 9.
Comparison of cumulative oil production of different refracturing methods.
Table 3 Comparison of cumulative oil production increment with different refracturing methods.
| Refracturing method | Initial daily oil production/tons | Cumulative oil production increment/104 tons | Cumulative oil production increment percentage/% |
|---|---|---|---|
| Refracturing of preexisting fractures | 22.1 | 0.388 | 21.9 |
| Existent fracture extension | 30.7 | 0.579 | 32.7 |
| Inter-fracture treatment | 42.3 | 0.878 | 49.6 |
| Temporary plugging and diverting inside fractures | 35.8 | 0.802 | 45.3 |
Fig. 8 shows all four methods can improve single-well productivity. In the initial stage of fracturing, the daily oil production of the four methods are all high, about three times that before refracturing. Inter-fracture treatment has better effect than the other three. However, some hydraulic fractures fail as the production goes on. After 2 000 days, all curves are almost overlapped, indicating similar production. Fig. 9 shows given the same number of fracturing clusters, inter-fracture treatment improves the communication of remaining oil between fractures, so it has the highest productivity. Temporary plugging and diverting inside fractures takes the second place. Existent fracture extension enables the communication of remaining oil in the distal end of fractures, improving the productivity to some extent. Refracturing of the preexisting fractures is limited in productivity increase.
Table 3 shows the cumulative oil production increment of the four refracturing methods. The refracturing of preexisting fractures has a small cumulative oil increment of only 21.9%, while the inter-fracture treatment has the highest cumulative oil increment. Apparently, inter-fracture treatment is the optimal refracturing method.
After the optimal refracturing method was sorted out, the effect of different fracturing clusters on refracturing was analyzed. The designed parameters were: 7, 10, 12, and 15 clusters, fracture half-length of 300 m, conductivity of 30 μm2·cm, stable bottom-hole flowing pressure of 8 MPa, and simulated production period of 5 years. The results are shown in Figs. 10 and 11. Clearly, the productivity is very sensitive to the number of fracturing clusters. As the number of fracturing clusters increases, the cumulative production continuously increases, but at a decreasing rate. After over 12 new clusters, adding new clusters further has lower production increment. When 15 new clusters are created, the initial daily oil production is the highest. After the production of three years, the daily oil production is the same for different numbers of clusters. The reason is that the formation energy depletes faster when more clusters are created. In addition, the reservoir in the study area has poor physical properties and no injection-production pattern is set up to supplement formation energy. Therefore, 12 new clusters work perfectly for the reservoir and maximize the productivity, delivering a cumulative oil production increment of 11 980 tons (Table 4). In comparison, this well produced only 6752 tons oil cumulatively in three years before the treatment.
Fig. 10.
Fig. 10.
Comparison of cumulative oil production with different fracturing clusters.
Fig. 11.
Fig. 11.
Comparison of daily oil production with different fracturing clusters.
Table 4 Comparison of cumulative oil production increment with different fracturing clusters.
| Number of new clusters | Cumulative oil production increment/104 tons | Cumulative oil production increment percentage/% |
|---|---|---|
| 7 | 0.878 | 49.6 |
| 10 | 1.030 | 58.1 |
| 12 | 1.198 | 67.6 |
| 15 | 1.239 | 69.9 |
3.2. Determination of refracturing timing
After the optimal refracturing method was ascertained, the stimulation effect at different refracturing timing was analyzed by using the refracturing productivity forecasting model. The 12-cluster inter-fracture treatment was used and the parameters were: fracture half-length of 300 m, conductivity of 30 μm2·cm, refracturing at the 2nd, 3rd, 4th and 5th year, stable bottom-hole flowing pressure of 8 MPa, and simulated production period of 5 years. The results are shown in Fig. 12, Fig. 13, and Table 5. Fig. 12 shows that the daily oil production shortly after refracturing increases sharply, but a later stimulation delivers a shorter period of effective stimulation. Fig. 13 shows that the cumulative oil production enhances significantly than without refracturing, and the cumulative oil production of the stimulation in the 2nd year is relatively higher in the early stage but becomes lower than that of the stimulation in the 3rd year in the later stage. Table 5 shows that refracturing in the 3rd year delivers the optimal stimulation effect, cumulatively increasing the oil production by 68.6%, while refracturing in the 5th year cumulatively increases the oil production only by 26.7%. In conclusion, the 3rd year is the optimal refracturing opportunity.
Fig. 12.
Fig. 12.
Comparison of daily oil production with different refracturing timings.
Fig. 13.
Fig. 13.
Comparison of cumulative oil production with different refracturing timings.
Table 5 Comparison of cumulative oil production increment with different refracturing timings.
| Refracturing timing | Initial daily oil production/tons | Cumulative oil production increment/104 tons | Cumulative oil production increment percentage/% |
|---|---|---|---|
| 2nd year | 32.3 | 1.069 | 59.6 |
| 3rd year | 31.5 | 1.231 | 68.6 |
| 4th year | 26.5 | 0.798 | 44.5 |
| 5th year | 22.8 | 0.469 | 26.7 |
When selecting the refracturing opportunity, the first things to be considered are the material basis and energy basis for refracturing. As production goes on, formation pressure would decrease, closure stress would increase, and fracture conductivity would decrease and fail at last. In the late stage of development, the development well would have insufficient formation energy supply, so crude oil can’t flow to the fractures though refracturing in the 4th and 5th years would provide high-seepage pathways. This results in poor refracturing effects. Therefore, the 3rd year is the optimal refracturing opportunity. In the development of similar tight oil reservoirs, the ideal refracturing well can be taken as a benchmark to quickly select and classify candidate wells. Then, the optimal refracturing opportunity can be defined based on factors, such as oil well production duration, hydraulic fracture conductivity, formation pressure retaining degree and ground stress distribution.
4. Optimization of interval count for temporary plugging and diversion
After the optimal refracturing method and timing are determined, it is necessary to work out the adding method and quantity of temporary plugging agents, which are crucial for the refracturing effect. After the initial fracturing, the fractures vary greatly in shape[28] due to the strong heterogeneity of the reservoirs in the fracturing intervals of the horizontal well, and the breakdown pressure of different positions in the horizontal well are different due to formation pressure variations. In this study, the breakdown pressure at different positions of the horizontal well were ranked by using the breakdown pressure forecasting model based on formation pressure variations, then the adding frequency and dosage of temporary plugging agents were worked out accordingly.
4.1. Breakdown pressure forecasting model
According to the variational principles in elasticity, the tangential tensile stress and radial compressive stress act on the borehole rocks jointly. The rock breakdown criterion equation is as follows:
When the tangential stress σθ meets the requirements of equation (3), the borehole rock would suffer tensile damage. At this point, the liquid injection pressure is the formation breakdown pressure. Zhu et al.[29,30,31] established the borehole stress field model of a perforated well considering formation pressure changes. The tangential stress of on the wellbore wall is as follows:
where
According to the rock breakdown criterion equation (3), by combining equations (4) and (5), as well as the formation pressures at different production times of a horizontal well, the tangential stress of perforations σθ at different hydrostatic pressures pw was calculated. When the tangential stress is high enough to overcome the rock tensile strength σt, the reservoir rock will break down. pw at this point is the formation breakdown pressure.
4.2. Division of temporary plugging and diversion intervals
With the impacts of formation pressure changes before production and in the 1st, 2nd, and 3rd year after production on the breakdown pressure considered, the breakdown pressure forecasting model was used to derive the breakdown pressure profiles of preexisting and new fractures in horizontal section of the example well at different production moments. Fig. 14 shows that the breakdown pressure is significantly affected by formation pore pressure and decreases as the production lasts longer. The breakdown pressure at different perforations vary greatly.
Fig. 14.
Fig. 14.
Breakdown pressure profiles of preexisting and new fractures in horizontal section of the example well.
The breakdown pressures at different positions of preexisting and new fractures were ranked into different levels. Similar pressures were classified into the same level. Table 6 shows the ranking result. At the fracturing site, the treatment pressure was determined according to the breakdown pressure. Fractures would initiate first in places with lower breakdown pressure. Fig. 15 shows the scheme of temporary plugging and diversion. The fracturing fluid firstly breaks down the perforation with the lowest breakdown pressure (Fig. 15a), and then temporary plugging agent was pumped into the fractures created first (Fig. 15b). Then, the fracturing fluid is pumped to create new fractures (Fig. 15c). The dosage of temporary agents is determined according to the number of early-created fractures and the number of perforation shots of each fracture. In the initial fracturing intervals of the example well shown in Table 6, the inter-fracture treatment method was selected; the breakdown pressure was classified into two levels; and temporary agents were added for only one time according to initial fracturing and production performance.
Fig. 15.
Fig. 15.
Temporary plugging and diversion diagram.
Table 6 Optimization of temporary plugging and diversion times for some intervals of the example horizontal well.
| Stage number | Horizontal section/m | Cluster number | Perforation depth/m | Refracturing method | Breakdown pressure/MPa | Classification | Number of temporary plugging and diversion |
|---|---|---|---|---|---|---|---|
| 9th stage | 2 140- 2 212 | Existent fracture 19 | 2 212 | no-refracturing | 37.3 | 1 | 1 |
| New fracture 1 | 2 176 | Inter-fracture treatment | 42.7 | 2 | |||
| Existent fracture 20 | 2 140 | no-refracturing | 38.3 | 1 | |||
| New fracture 2 | 2 105 | Inter-fracture treatment | 44.6 | 2 | |||
| 10th stage | 1 995- 2 070 | Existent fracture 21 | 2 070 | no-refracturing | 38.2 | 1 | |
| New fracture 3 | 2 032 | Inter-fracture treatment | 42.5 | 2 | |||
| Existent fracture 22 | 1 995 | no-refracturing | 36.6 | 1 |
5. Field application
To verify the method for optimizing the refracturing timing of horizontal wells, the preceding study results were applied to some horizontal wells in the same block to optimize the refracturing method, refracturing timing, and times of temporary plugging reorientation. The treated well has a 650 m long horizontal section and a 480 m long oil- bearing sandstone zone. Its initial fracturing was a small-scale job with four clusters. The inter-fracture treatment and preexisting fracture extension methods were selected. Three new clusters were created and four preexisting clusters were extended, which made a total of seven clusters. The well was stimulated using the single- packer commingled volume fracturing method, and the plugging agent was a water-soluble temporary plugging agent. According to the breakdown pressure at the perforations of the horizontal well, the well was divided into two stages, and two times of temporary plugging and diversion were performed (Table 7). Based on the number of perforation shots, the dosage of temporary plugging agent was worked out. In the four layers of the first stage, 1 110 perforation shots used 17.3 kg of temporary plugging agent. In the two layers of the second stage, 1 350 perforation shots used 21.1 kg of temporary plugging agent.
Table 7 Optimization of temporary plugging and diversion stages for the treated well.
| Stage number | Fracturing section/m | Perforation thickness/m | Perforation density/(shots•m-1) | Perforation shots | Refracturing method | Breakdown pressure/MPa | Classification | Times of temporary plugging and diversion |
|---|---|---|---|---|---|---|---|---|
| 1 | 1 945-2 015 | 30 | 10 | 300 | Inter-fracture treatment | 49.5 | 3 | 2 |
| 2 | 1 803-1 825 | 21 | 10 | 210 | Existent fracture extension | 41.2 | 1 | |
| 3 | 1 703-1 775 | 70 | 10 | 700 | Inter-fracture treatment | 46.3 | 2 | |
| 4 | 1 652-1 682 | 30 | 10 | 300 | Existent fracture extension | 41.1 | 1 | |
| 5 | 1 540-1 625 | 30 | 10 | 300 | Existent fracture extension | 42.3 | 1 | |
| 6 | 1 460-1 525 | 65 | 10 | 650 | Inter-fracture treatment | 46.3 | 2 | |
| 7 | 1 364-1 463 | 30 | 10 | 300 | Existent fracture extension | 40.5 | 1 |
The well treatment was successful, with the displacement of 4.8 m3/min. The proppant concentration for the intervals were 7%, 14%, 21%, 25%, and 30% respectively. Totally, 630 m3 fracturing fluid and 78 m3 proppant were used. Before and after temporary plugging agent was pumped for the first time, the well was displaced without proppant at the displacement pressure of 33.0 MPa, and the pump-off pressure was 8.5 MPa. After temporary plugging agent was pumped in for the second time, the tubing pressure increased from 32.8 MPa to 38.0 MPa, and the pump-off pressure was 13.7 MPa, which indicated that the temporary plugging and diversion was successful (Fig. 16). After refracturing, the oil production of the well increased from 1.3 tons to 11.6 tons. At the same time, other typical wells in the block were also refractured, with great improvement of development effect (Fig. 17).
Fig. 16.
Fig. 16.
Volume fracturing curve of the example well.
Fig. 17.
Fig. 17.
Production rate of wells P1, P 2, P 3, and P 4 before and after refracturing.
The field applications have further verified that the proposed method is practical and reliable. In the development of similar tight oil reservoirs, field engineers can use the ideal refracturing well as benchmark to preliminarily select wells for refracturing. Then, numerical simulation is performed to evaluate the material basis and energy basis of the wells to be treated and determine the optimal refracturing method and timing. The optimal refracturing method proposed in this study, i.e. inter-fracture treatment, can be directly applied, while the refracturing opportunity should be selected depending on the fracture conductivity and formation energy retaining degree of the wells to be treated. In the end, the breakdown pressure forecasting model is used to determine the times of temporary plugging and diversion and the dosage of temporary plugging agent.
6. Conclusions
A novel ideal refracturing well was established by considering the parameters of candidate horizontal wells for refracturing. By calculating Euclidean distance and similarity coefficient between the ideal well and the candidate wells, the candidate wells can be classified and prioritized according to refracturing potential. This together with numerical simulation has opened a new idea for timing selection and engineering application of refracturing.
The approach was tested in an oilfield in Songliao Basin and the simulation results show that the order of productivity enhancing extent under the same fracturing clusters is: refracturing new sections between preexisting fractures, temporary plugging and diversion inside preexisting fractures, extending preexisting fractures, refracturing of preexisting fractures, and no-refracturing. For the same refracturing method, the later the refracturing opportunity, the shorter the effective time is. In our study, the 3rd year is the optimal refracturing opportunity. This optimization method can be used in other similar tight oil reservoirs.
The breakdown pressure forecasting model considering the variation of pore pressure for different production time can be used to determine the opportunity of temporary plugging and diversion and the dosage of temporary plugging agent can be determined based on the number of fracturing clusters and perforation shots. Average daily oil production increased from 2.3 tons/d to 16.5 tons/d in the field test, indicating good refracturing effect.
Nomenclature
c—correction factor, dimensionless;
di—Euclidean distance, dimensionless;
i—sequence number of candidates;
j—sequence number of factors affecting refracturing timing;
m—number of factors affecting refracturing timing;
n—number of candidates;
pp—formation pressure, MPa;
pw—injection pressure, MPa;
si—similarity coefficient, dimensionless;
$x_{ij}^{*}$—normalized value of the matrix, dimensionless;
i—number of candidates;
j—number of factors affecting refracturing effect;
α—Biot constant, dimensionless;
δ—permeability coefficient, dimensionless;
θ—perforation azimuth angle, (°);
θ°—fracture propagation azimuth angle, (°);
υ—Poisson’s ratio of rock, dimensionless;
σH—maximum horizontal main stress, MPa;
σh—minimum horizontal main stress, MPa;
σt—tensile strength of rock, MPa;
σv—vertical stress, MPa;
σz—wellbore axis stress, MPa;
σθ—tangential stress on the wellbore wall, MPa;
ϕ—porosity, %.
Reference
New research progress of Jurassic tight oil in central Sichuan Basin
DOI:10.11698/PED.2016.06.04
URL
[Cited within: 1]
The resource potential, "fractured" reservoir, reservoir type and stimulation technology of Jurassic tight oil in central Sichuan basin were investigated. Based on the evaluation method of tight oil resource, the amount of oil resources of the five Jurassic layers were estimated at 1.6 billion tons, showing that the Jurassic oil resource potential in central Sichuan Basin is huge. Integrated analysis of static and dynamic data including core-description, thin section examination, well test and exploration show Jurassic reservoirs are fracture-pore reservoir with ultra-low porosity, super-low permeability, rather than single "fractured" reservoir believed before. Jurassic reservoirs are tight oil reservoir with the characteristics of near source charge and continuous distribution. The high-quality hydrocarbon source, reservoir with better physical properties and fracture are the main factors controlling tight oil enrichment. "Horizontal well + volume fracturing" of Shayi Member tight sandstone reservoir and the "horizontal well + fracture acidizing" for the Da'anzhai Member shell limestone reservoir have achieved good stimulation effect.
Geological features and exploration fields of tight oil in the Cenozoic of western Qaidam Basin, NW China
DOI:10.1016/S1876-3804(17)30024-1
URL
[Cited within: 1]
Using a large amount of drilling and experimental analysis data, this paper evaluates four potential fields of tight oil exploration in western Qaidam Basin from comprehensive analysis of geological conditions such as sedimentary environments, source rock evaluations, reservoir characteristics, and source-reservoir relationships. Influenced by continuous uplift of Tibet Plateau since Paleogene, the sedimentary environment of the western Qaidam Basin exibits three characteristics:(1) a paleo-topographic configuration consisted of inherited slopes, depressions and paleohighs;(2) frequent alternation of relative humid and arid paleoclimate; and(3) oscillation of salinity and level of the paleo-lake water. Preferential paleo-environment resulted in two sets of large-scale source rocks with high efficiency and two types of large-scale tight reservoir rocks(siliclastic and carbonate), deposited during the late Paleogene to early Neogene. The above source and reservoir rocks form favorable spatial relationships which can be classified into three categories: symbiotic, inter and lateral. Based on sedimentary environments and reservoir types, tight oil resource in western Qaidam Basin can be divided into four types, corresponding to four exploration fields: salty lacustrine carbonate tight oil, shallow lake beach-bar sandstone tight oil, delta-front-sandstone tight oil and deep lake gravity-flow-sandstone tight oil. The temporal and spatial distribution of tight oil has characteristics of layer concentration, strong regularity and large favorable area, in which the saline lacustrine carbonate and shallow lake beach-bar sandstone tight oil are the best exploration targets in the western Qaidam Basin.
Lower limits and grading evaluation criteria of tight oil source rocks of southern Songliao Basin, NE China
DOI:10.1016/S1876-3804(17)30058-7
URL
[Cited within: 2]
With southern Songliao Basin as the target area, the hydrocarbon expulsion intensity of source rocks was quantitatively evaluated based on the material balance method. Under the "Overpressure" module of Petro Mod software, the overpressure history of the source rocks was evaluated. According to the relationships among hydrocarbon expulsion intensity, residual organic carbon content and overpressure within source rocks and related inflection points, the lower limits of tight oil source rocks were determined: hydrocarbon expulsion amount of per unit mass rock 2 mg/g, residual hydrocarbon content 0.8%, and overpressure 1 MPa. The source rocks with hydrocarbon expulsion 8 mg/g, a residual organic carbon content 2.0%, and overpressure 7 MPa were defined as the limits of excellent source rocks. As a result, the tight oil source rocks can be divided into three types, excellent source rocks(typeⅠ), inefficient source rocks(typeⅡ) and invalid source rocks(type Ⅲ). The evaluation has been made for favorable areas distribution range of tight oil in Southern Songliao Basin according to the lower limits and grading evaluation criteria of tight oil source rocks. The result shows that the excellent source rocks have an obvious control on the distribution of tight oil, areas with excellent source rocks and nearby formations are favorable for the accumulation of tight oil.
Discussion on effective development techniques for continental tight oil in China
DOI:10.1016/S1876-3804(14)60025-2
URL
[Cited within: 1]
Based on the main geological features and technical breakthroughs made in tight oil exploration, the major challenges facing tight oil development are analyzed, and the key technical trend for tight oil development is discussed in this paper. Mainly found in continental deposits, tight oil reservoirs in China feature small area, poor physical properties, big differences in geological characteristics between different basins, but low porosity, low permeability and pressure in general. In contrast to marine tight oil, tight oil in continental deposits faces such challenges as low production and recovery, and poor economics. Through nearly three years of research and pilot test, an integrated development mode with repeated fracturing of horizontal wells as the principal technique has been proposed, which includes integrated design, platform long horizontal well drilling, massive volume fracturing, re-fracturing stimulation, controlled production, factory-like operation, concentrated surface construction etc. It is recommended that study be strengthened on basic tight oil development theory, practical development technologies, and economic evaluation of tight oil development over the whole life cycle.
Field test of volume fracturing for horizontal wells in Sulige tight sandstone gas reservoirs
DOI:10.1016/S1876-3804(14)60098-7
URL
[Cited within: 1]
Based on the development degree of natural micro-fractures, rock brittleness and two-direction stress and other geological conditions of the Sulige gas field, the feasibility of using volume fracturing to increase production was analyzed and verified by field test. The Sulige gas field, a typical tight sandstone gas reservoir, has developed natural micro-fractures, with fracture complex index of 0.3610.5, rock brittleness index distribution in the 366152 and two-direction stress heterogeneity factor of 0.17. From the development experiences of unconventional gas reservoirs abroad, the geological conditions in the Sulige gas field is suitable for volume fracturing. Through lab experiments and pilot field tests, a volume fracturing technology for horizontal wells has been developed, which features “fracturing with low-viscosity liquid, carrying proppant with high-viscosity liquid, combination of multi-scale proppants, and massive fracturing at a high injection rate”. The technique had been applied in 42 wells of the Sulige tight gas field by the end of 2013. The initial production of wells treated by this approach is 1.2 times that of the adjacent wells treated by conventional fracturing, indicating that the technique can enhance the production of the horizontal wells in the Sulige gas field substantially.
Hybird stimulated reservoir volume technology for tight oil in Shulu sag
Adsorption damage and control measures of slick-water fracturing fluid in shale reservoirs
The slick-water polymer adsorption damage and control measures in shale were examined using a shale pack model of the Ordovician Wufeng Formation ilurian Longmaxi Formation in the Changning block of the Sichuan Basin. The adsorption law of slick water under different displacement time, concentrations, pH values and temperatures of polymer were tested by traditional displacement experiment and UV-Vis spectrophotometer. The adsorption equilibrium time was 150 min, the amount of adsorption was proportional to the concentration of the polymer, and the maximum adsorption concentration was 1 800 mg/L. With the increase of pH value, the adsorption capacity decreased gradually, the adsorption capacity increased first and then decreased with the increase of temperature, and the adsorption capacity was the largest at 45 C. The adsorption patterns of polymers on shale were described by scanning electron microscopy and magnetic resonance imaging. It is proved that the adsorption of polymer on shale led to the destruction of the network structure of anionic polyacrylamide molecules, and the shale adsorption conformation was characterized qualitatively. Finally, according to the adsorption law and adsorption mechanism, it is proposed to reduce the adsorption quantity of polymer on shale surface by using hydrogen bond destruction agent. The effects of hydrogen bond destruction on four kinds of strong electronegative small molecules were compared, the hydrogen bond destroyer c was the best, which lowered the adsorption capacity by 5.49 mg/g and recovered permeability to 73.2%. The research results provide a reference for the optimization of construction parameters and the improvement of slickwater liquid system.
Analytical analysis of fracture conductivity for sparse distribution of proppant packs
DOI:10.1088/1742-2140/aa6215
URL
[Cited within: 1]
Conductivity optimization is important for hydraulic fracturing due to its key roles in determining fractured well productivity. Proppant embedment is an important mechanism that could cause a remarkable reduction in fracture width and, thus, damage the fracture conductivity. In this work a new analytical model, based on contact mechanics and the Carman-Kozeny model, is developed to calculate the embedment and conductivity for the sparse distribution of proppant packs. Features and controlling factors of embedment, residual width and conductivity are analyzed. The results indicate an optimum distance between proppant packs that has the potential to maintain the maximum conductivity after proppant embedment under a sparse distribution condition. A change in the optimum distance is primarily controlled by closure pressure, the rock elastic modulus and the proppant elastic modulus. The proppant concentrations and the poroelastic effect do not influence this optimum distance.
Laboratory study of proppant on shale fracture permeability and compressibility
DOI:10.1016/j.fuel.2018.02.141 URL [Cited within: 1]
A fractal analysis of fracture conductivity considering the effects of closure stress
DOI:10.1016/j.jngse.2016.04.022
URL
[Cited within: 1]
61An acid-rock reaction test installation has a self-owned intellectual property right.61Fracture conductivity model considering closure stress was developed.61A combination of the digital calculation method and the fractal theory was performed.61The effect of fractal dimensions and rock elastic parameters was discussed.
Pressure transient behavior of horizontal well with time-dependent fracture conductivity in tight oil reservoirs
A comprehensive overview on recent developments in refracturing technique for shale gas reservoirs
DOI:10.1016/j.jngse.2017.07.019
URL
[Cited within: 1]
Refracturing is described as hydraulic fracturing the formation which has earlier been hydraulically fractured. Presently, it is among the most widely used restimulation techniques. The technique to refracture the wells which are less productive and having poor reservoir quality has been applied since 1940s. The perception, however, is that refracturing technique is generally unsuccessful. But with the recent advancement in technology and improved refracturing techniques, many operators have now successfully implemented this technique for not only poor but also good quality reservoirs to increase production rate and to enhance ultimate gas recovery from shale gas wells. It also serves as countermeasure against the declining rate of gas price, because refracturing operation is less costly compared to drilling and completing a new well. Refracturing operation, in general, is a complex process. Additional research and development is needed for its successful implementation and higher reliability. This paper explores the attributes responsible for successful refracturing treatment and conditions limiting the application of refracturing treatment. Furthermore, it presents the procedure for candidate well identification and discusses the refracturing treatment design, treatment diagnostic techniques and economical evaluation of the treatment. In addition, it also highlights the challenges for refracturing treatment. It also presents two case studies to support the concept and demonstrate recent developments. The paper provides significant insight into the refracturing technology and the guidelines for its successful application in shale gas reservoirs.
Comprehensive optimization methodology for stimulation design of low-permeability unconventional gas reservoirs
Renewing mature shale wells through refracturing
Re-fracturing mode and fracture parameter optimization for stripper well in tight oil reservoir
The re-fracturing of oil well is one of main offensive measures to increase the single well production of stripper well in tight oil reservoir. In order to improve the yield-increasing effect of re-fracturing,it is necessary to optimize the perforation mode and fracture parameter. Taking a tight oil reservoir in Xinjiang Changji Oilfield as an example,the prediction model of re-fracturing was established and the productivity index of stripper well in different perforation mode or fracture half-length or conductivity was studied using the numerical simulation method. The results show that,compared to the mode in old perforation location,the mode in new perforation location is more significant in stimulation effect,and the more new perforation the higher production. The effect of fracture half-length on re-fracturing is next only to fracturing series,The yield increase along with the extend of fracture half-length.Due to the low permeability in tight oil reservoir,the fracture conductivity only slightly affects the reservoir performance.
Lessons learned: Refracs from 1980 to present
Restimulation of unconventional reservoirs: When are refracs beneficial?
DOI:10.2118/136757-PA URL [Cited within: 1]
Hybridising human judgment, AHP, grey theory, and fuzzy expert systems for candidate well selection in fractured reservoirs
DOI:10.3390/en10040447
URL
[Cited within: 1]
The selection of appropriate wells for hydraulic fracturing is one of the most important decisions faced by oilfield engineers. It has significant implications for the future development of an oilfield in terms of its productivity and economics. In this study, we developed a fuzzy model for well selection that combines the major objective criteria with the subjective judgments of decision makers. This was done by fusing the analytic hierarchy process (AHP) method, grey theory and an advanced version of fuzzy logic theory (FLT). The AHP component was used to identify the relevant criteria involved in selecting wells for hydraulic fracturing. Grey theory was used to determine the relative importance of those criteria. Then a fuzzy expert system was applied to fuzzily process the aggregated inputs using a Type-2 fuzzy logic system. This undertakes approximate reasoning and generates recommendations for candidate wells. These techniques and technologies were hybridized by using an intercommunication job-sharing method that integrates human judgment. The proposed method was tested on data from an oilfield in Western China and finally the most appropriate candidate wells for hydraulic fracturing were ranked in order of their projected output after fracturing.
A comprehensive overview on recent developments in refracturing technique for shale gas reservoirs
DOI:10.1016/j.jngse.2017.07.019
URL
[Cited within: 1]
Refracturing is described as hydraulic fracturing the formation which has earlier been hydraulically fractured. Presently, it is among the most widely used restimulation techniques. The technique to refracture the wells which are less productive and having poor reservoir quality has been applied since 1940s. The perception, however, is that refracturing technique is generally unsuccessful. But with the recent advancement in technology and improved refracturing techniques, many operators have now successfully implemented this technique for not only poor but also good quality reservoirs to increase production rate and to enhance ultimate gas recovery from shale gas wells. It also serves as countermeasure against the declining rate of gas price, because refracturing operation is less costly compared to drilling and completing a new well. Refracturing operation, in general, is a complex process. Additional research and development is needed for its successful implementation and higher reliability. This paper explores the attributes responsible for successful refracturing treatment and conditions limiting the application of refracturing treatment. Furthermore, it presents the procedure for candidate well identification and discusses the refracturing treatment design, treatment diagnostic techniques and economical evaluation of the treatment. In addition, it also highlights the challenges for refracturing treatment. It also presents two case studies to support the concept and demonstrate recent developments. The paper provides significant insight into the refracturing technology and the guidelines for its successful application in shale gas reservoirs.
Refracture candidate selection using hybrid simulation with neural network and data analysis techniques
DOI:10.1016/j.petrol.2014.07.036
URL
[Cited within: 1]
By now very few analytical models have been developed to select well refracture candidates due to complicated multi-parameter relationships. In this study, we proposed a new method by merging mathematical data analysis with feed forward back propagation neural network utilizing post-fracturing data. The model preference is thereby based on the correlation coefficients of several selected independent variables against production performance. The solution to this expense is a tool that can identify restimulation candidates quickly and economically. We employ two mathematical analysis techniques to filter several independent yet influential parameters as inputs. These parameters are supposed to be primary factors with high impact on potential production improvement. Then we use these well data to train an artificial neural network (ANN) to predict post-fracture production. The errors of the best samples should decrease consistently along with the training samples. A minimal error of the training sets is not necessary because over-fitting of the network could be memorizing rather than generalizing. The testing results showed that there is higher than 80% prediction accuracy, which is good enough for decision making. This methodology gives credible prediction results when it is applied in Zhongyuan oilfield and provides the operators with useful recommendations to make decisions for restimulation. (C) 2014 Elsevier B.V. All rights reserved.
Reservoir and completion considerations for the refracturing of horizontal wells
From face detection to fractured reservoir characterization: Big data analytics for restimulation candidate selection
Restimulation design considerations and case studies of haynesville shale
Recent advancement in temporary diversion technology for improved stimulation performance
Integrating fully coupled geomechanical modeling with microsesmicity for the analysis of refracturing treatment
DOI:10.1016/j.jngse.2017.07.008 URL [Cited within: 1]
Understanding the applicability and economic viability of refracturing horizontal wells in unconventional plays
Identification of refracturing reorientation using decline- analysis and geomechranical simulator
Quantitative phase field modeling of hydraulic fracture branching in heterogeneous formation under anisotropic in-situ stress
DOI:10.1016/j.jngse.2018.06.009 URL [Cited within: 1]
Hydraulic fracture initiation and propagation from wellbore with oriented perforation
DOI:10.1007/s00603-014-0608-7
URL
[Cited within: 1]
Considering the influence of casing, analytical solutions for stress distribution around a cased wellbore are derived, based on which a prediction model for hydraulic fracture initiation with the oriented perforation technique (OPT) is established. Taking well J2 of Z5 oilfield for an example, the predicted initiation pressure with the OPT of our model is about 4.2 MPa higher than the existing model, which neglects the influence of casing. In comparison with the results of laboratory fracturing experiments with OPT on a 400 x 400 x 400 mm(3) rock sample for a cased well with the deviation of 45A degrees, the fracture initiation pressure of our model has an error of 3.2 %, while the error of the existing model is 6.6 %; when the well azimuth angle is 0A degrees and the perforation angle is 45A degrees, the prediction error of the fracture initiation pressure of the existing model and our model are 3.4 and 7.7 %, respectively. The study verifies that our model is more applicable for hydraulic fracturing prediction of wells with OPT completion; while the existing model is more suitable for hydraulic fracturing with conventional perforation completion.
Hydraulic fracture initiation and propagation: Roles of wellbore trajectory, perforation and stress regimes
DOI:10.1016/S0920-4105(00)00056-5
URL
[Cited within: 1]
This paper develops a generic model for predicting hydraulic fracture initiation from arbitrarily oriented wellbores. For a given in-situ stress condition and wellbore orientation parameters, the model predicts the fracture initiation pressure and the orientation and location of fractures on the wellbore wall. The model has been applied in a series of in-situ stress conditions to study the effect of wellbore orientation on fracture initiation using non-dimensional parameters, which have enhanced the applicability of presented results for any stress condition. Closed-form analytical solutions are also obtained for initiation of longitudinal, transverse and complex multiple fractures from vertical and horizontal wellbores with and without perforation. A numerical model is then incorporated in the study to analyze the propagation behavior of initiated fractures. Causes of fracture initiation at non-preferred locations and its effects on fracture propagation pressure and fracture volume due to twist of these initiated fractures during propagation are studied and discussed. Results from the analytical and numerical models used in this study are interpreted with a particular effort to enlighten the causes of abnormally high treating pressures during hydraulic fracture treatments.
An investigation of hydraulic fracturing initiation and near- wellbore propagation from perforated boreholes in tight formations
DOI:10.1007/s00603-014-0595-8
URL
[Cited within: 1]
In this study, hydraulic fracturing tests were conducted on 10 and 15 cm synthetically manufactured cubic tight mortar samples. The use of cube samples allowed application of three independent stresses to mimic real far field stress conditions. A true triaxial stress cell was used for this purpose. The lab test parameters were scaled to simulate the operations at field scale. The hole and perforations were made into the sample after casting and curing were completed. Various scenarios of vertical and horizontal wells and in situ stress regimes were modeled. These factors are believed to play a significant role in fracture initiation and near-wellbore propagation behavior; however, they are not independent parameters, hence should be analyzed simultaneously. In addition to experimental studies, analytical solutions were developed to simulate the mechanism of fracture initiation in perforated boreholes in tight formations. Good agreements were observed between the experimental and analytical results. The results of this study showed that a lower initiation pressure is observed when the minimum stress component is perpendicular to the axis of the perforations. It was also seen that, even when the cement sheath behind the casing fails, the orientation of the perforations may affect the initiation of the induced fracture noticeably. Furthermore, it was found that stress anisotropy influences the fracturing mechanism in a perforated borehole, and affects the geometry of the initiated near-wellbore fracture.
