Next Article in Journal
Global Modeling of Heat-Integrated Distillation Column Based on Limited Local Measurements
Next Article in Special Issue
Co-Gelatinization Modification of Iodine–Starch and Its Performance in Drilling Fluid
Previous Article in Journal
An Injection-Mold Based Method with a Nested Device for Microdroplet Generation by Centrifugation
Previous Article in Special Issue
An Integrated Model for Acid Fracturing without Prepad Considering Wormhole Growth
 
 
Search for Articles:
Title / Keyword
Author / Affiliation / Email
Journal
Article Type
 
 
Advanced Search
 
Section
Special Issue
Volume
Issue
Number
Page
 
Journals
Processes
Volume 12
Issue 3
10.3390/pr12030482
processes-logo
Submit to this Journal Review for this Journal Propose a Special Issue
► Article Menu

Article Menu

share Share announcement Help format_quote Cite question_answer Discuss in SciProfiles
first_page
settings
Order Article Reprints
Font Type:
Arial Georgia Verdana
Font Size:
Aa Aa Aa
Line Spacing:
Column Width:
Background:
Article

Research and Applications of New Fracturing Technology in Low-Abundance and Greater-Depth Well LN-1 Reservoirs

by
Minghua Shi
1,
Dechun Chen
1,*,
Liangliang Wang
1,*,
Tengfei Wang
2,
Wei Song
1 and
Jiexiang Wang
1
1
School of Petroleum Engineering, China University of Petroleum (East China), Qingdao 266580, China
2
College of Chemistry & Environmental Engineering, Yangtze University, Jingzhou 434023, China
*
Authors to whom correspondence should be addressed.
Processes 2024, 12(3), 482; https://doi.org/10.3390/pr12030482
Submission received: 16 January 2024 / Revised: 25 February 2024 / Accepted: 26 February 2024 / Published: 27 February 2024
(This article belongs to the Special Issue Oil and Gas Drilling Rock Mechanics and Engineering)
Browse Figures
Versions Notes

Abstract

:
The upper Shasi reservoir in the LN block is characterized by low abundance and greater depth, low porosity, low permeability, and low pressure. Due to high water injection pressure, the LN block has been developed in an elastic way. The natural productivity of oil wells in this block is low, but the productivity can be improved after fracturing. However, the field development effects show that the oil well has high initial production, but rapid decline and rapid pressure drop. At present, the recovery factor of this block is only 0.38%, and it is difficult to realize the economic and effective development of a difficult-to-develop block by conventional fracturing technology. Based on the geological characteristics of the LN block and the fracturing experience of adjacent wells, the fracturing process is optimized and the key fracturing parameters are determined in combination with the sand body distribution and logging curve of well LN-1. Due to the low-pressure coefficient and medium water sensitivity of well LN-1, a new high-efficiency stimulation fracturing fluid system was selected and the formula of the fracturing fluid system was formed. The cluster perforating process is optimized according to reservoir differences, and the perforating “sweet spot” is optimized. Based on the sand body spread point of well LN-1, the high diversion channel technology and the temporary plugging and turning fracturing technology are selected to form a new fracturing and stimulation technology suitable for this kind of oil reservoir. A fracturing test was performed in layers 17# (electrical sequencing number) and 22# of well LN-1. The initial oil production was 12.5 t/d, and the stimulation effect was significantly higher than the 8.3 t/d (general fracturing) of adjacent wells. At present, the well LN-1 has been producing steadily for more than six months, and the results of this work can provide technical guidance for the efficient development of low-abundance and greater-depth oil reservoirs that are difficult to develop.

1. Introduction

Since the 1970s, a series of studies have been carried out at home and abroad for low-porosity, low-permeability, low-pressure, and low-abundance oil reservoirs, and so far, it has been integrated into a variety of technical directions, including carbon dioxide and natural gas injection (used to increase reservoir pressure and facilitate crude oil flow) [1,2], microbial-enhanced oil recovery (employed to improve reservoir conditions and increase abundance) [3,4,5], as well as horizontal well drilling and multi-well development (utilized to expand contact area) [6,7]. Compared with the above stimulation technology, fracturing technology has the advantages of simple construction, strong effectiveness, prominent pertinence, and good controllability. It can increase the reservoir seepage rate quickly, increase oil well productivity and collection rate, and reduce oil pollution and investment in the reservoir. In addition, the operation position can be flexibly adjusted during fracturing construction, which greatly reduces the risk of exploration projects and provides technical services for the development of old oilfields. In recent years, fracturing technology has received a lot of attention and achieved remarkable development. Methods such as fine fracturing design optimization (in situ stress description technology, fracturing parameter optimization, etc.), improvement of fracturing effect (low damage and high performance), fracturing fluid system (low-concentration guanidine gum fracturing liquid system, emulsion-associated fracturing liquid system, foam fracturing liquid system, etc.), efficient construction technology, mechanical packer stratified fracturing, ball stratified fracturing, pumped bridge plug, cementing slide sleeve, coiled tubing packer driving, and other unconventional fracturing processes have been gradually applied in recent years [8,9,10].
The upper Shasi reservoir in the LN block is characterized by low porosity, low permeability, low pressure, and low abundance. Due to high water injection pressure, elastic development methods have been adopted. The natural productivity of the oil well in this block is low, and the productivity can be increased by fracturing. After fracturing, the initial production increases significantly, but afterward, the productivity and the pressure decline fast. The current oil recovery factor of the oil reservoir is only 0.38%. It is worth noting that although hydraulic fracturing technology effectively enhances productivity, it often comes with the trends of high initial production, rapid decline, and swift pressure reduction. The reasons for this phenomenon could include the gradual closure of fractures or decreased fluid mobility in crude oil, resulting in a rapid decline in production. The practice shows that it is difficult for conventional general fracturing to fully transform each reservoir in the longitudinal direction, and the uneven transformation effect of each layer leads to the general development effect of the block [11,12,13,14,15]. Therefore, it is necessary to explore a new fracturing stimulation technology combined with the geological characteristics of the reservoir in the LN block [16,17,18,19,20].
The LN block is located in the descending panel of the QN fault in the steep slope zone in the north of the QN depression. The target layer is the upper Shashi reservoir. The buried depth of the reservoir is 3350 m, with an average porosity of 8.9% and an average permeability of 9.0 × 10−3 µm2. The formation temperature is 128.5 °C, and the geothermal gradient is 3.54 °C/100 m. The formation pressure is 32.14 MPa and the pressure coefficient is 1.03. It is a structural lithologic reservoir with normal pressure, high temperature, low porosity, low abundance, and low permeability. The reserve abundance of the developed Shasi upper region is 46.78 × 104 t/km2, with low reserve abundance, low production capacity of kilometers (average 2.3 t/d.km), and poor material foundation. At present, the completion of drilling shows that the reservoir characteristics change quickly, that there are certain geological risks in oil reservoir prediction, and that it is difficult to use the horizontal well economically and effectively, so this block adopts a straight inclined well development [21,22,23,24]. According to the oil test and production dynamic data, the natural productivity of the oil well is low, and the productivity can be increased after fracturing. Based on the geological characteristics of this difficult-to-develop block, an optimum study of fracturing technology and construction parameters is carried out.
In order to realize the green and efficient production of tight reservoirs, Gao et al. [25] innovatively put forward an integrated fracturing and oil production technology. This technology does not require flow back after fracturing and can make full use of fracturing energy and rubber-breaking fluid. The experimental results show that the technology has a good effect on improving oil recovery under the conditions of reservoir pressure 3.5 MPa, temperature 140 °C, and the presence of CO2. To further improve the development effect of the Mahu oil reservoir, Wu et al. [26] first established a multi-fracture propagation calculation model, aiming at the problem of uneven fracture distribution in the long section of horizontal well with the multi-cluster fracturing process, and realized a rapid solution. The research results can provide theoretical and technical guidance for realizing the efficient construction of multi-cluster fractures in long stages in the sandstone reservoir of the same type. The timely sealing technology of fractures is helpful in ensuring the long-term efficient production of oil wells. To further explore the optimal time for crack sealing, Xing et al. [27] established a stress distribution prediction model to accurately calculate the stress distribution around the artificial crack before seal failure. The research results can reveal the propagation behavior of fractures and improve the theoretical system of hydraulic fracturing technology.
The development of old oilfields faces multiple contradictions and challenges, in which low-abundance reservoirs are indeed the key issues and main tasks. The productivity of low-abundance reservoirs can be improved after fracturing, so new fracturing technology has received more and more attention. In view of the geological characteristics of the Fuyu oilfield, such as shallow burial depth, low temperature, low pressure, and low permeability, as well as the development characteristics of high-composite water content (95%) and the interlacing of artificial and natural fractures, Qi et al. [28] proposed a new method of refracturing with controllable permeability. The formulation of a temporary plugging agent with controllable permeability was optimized. Field test results show that surface-controlled permeability fracturing technology can effectively improve oil recovery. Tao et al. [29] developed a fuzzy-ball temporary plugging fluid (FTPF) that turns to fracture and water cutting after re-fracturing to combat water intrusion in tight sandstone gas wells. The effect of this technology on enhanced oil recovery is verified by physical simulation experiments. The average gas production of FTPF increased by 64.8% after refracturing in the Sulige gas field in Northwest China.
The concise review of the abovementioned research shows that the use of conventional fracturing technology can help to increase capacity in the short term. Nevertheless, conventional fracturing technology makes it difficult to achieve long-term economic and effective development of the LN blocks with the characteristics of low abundance and greater depth, low porosity, low permeability, and low pressure. In this work, we first conducted a detailed analysis of the geological characteristics of the LN block, including structural characteristics, mineral composition, reservoir characteristics (permeability, sensitivity, oil–water properties, temperature–pressure system, sand body distribution, reservoir stress), and the log curve of the well LN-1. Secondly, the difficulty of fracturing in the LN block is analyzed. Based on the above information, the key fracturing and stimulation techniques suitable for the well LN-1 are subsequently proposed. This series of technologies mainly includes new high-efficiency stimulation fracturing fluid systems, cluster perforating technology, high diversion channel fracturing, temporary plugging, and diversion fracturing technology. Finally, the construction process and effect of well LN-1 are introduced in detail. The new fracturing stimulation series technology has achieved good application in well LN-1, which can provide a reference for similar characteristic blocks.

2. Geological Characteristics and Fracturing Difficulties of the LN Block

2.1. Geological Characteristics of the LN Block

2.1.1. Structural Feature

LN block is located in the northwestern steep slope zone of the QN depression, as shown in Figure 1. The structure is a nose-like structure with a high northern point and low southern point controlled by the large QN fault of the northern boundary, and the stratigraphic dip is 11°–24°. The east and west wings are steeper, while the south wings are slower. The high point is located in the north of well LN-1, where the structural depth is −2960 m, and the lowest part is located in the south of well LN-2 and the west of well LN-3. The structural depth is −3340 m and the structure amplitude is 380 m. The fan delta-turbidite fan sedimentary system and underwater fan sedimentary system were mainly developed during the deposition period of the upper and lower pure sub-members of Shasi in the LN block.

2.1.2. Mineral Composition

The lithology is mainly feldspar siltstone and the main clastic minerals are quartz, feldspar, and cuttings. The average quartz content is 45%. The average feldspar is 34%, mainly potassium feldspar and plagioclase. The average amount of cuttings is 21%, and the cuttings are mainly metamorphic rock cuttings. The cement consists of calcite and dolomite, and the complex base is mainly argillaceous. The clay minerals are dominated by illite with an average content of 36%, followed by kaolin with an average content of 16%, and chlorite with an average content of 7%. The interlayer ratio is 36% and the intralayer ratio is 22%.

2.1.3. Reservoir Characteristics

(1)
Permeability
According to the results of log secondary interpretation, the porosity of the upper pure lower sub-member of Shasi is 2.7–21.2%, with an average of 8.9%, and the permeability is 0.136–19.207 × 10−3 µm2, with an average of 9.0 × 10−3 µm2.
(2)
Sensibility
The oil reservoirs are weak-to-medium water sensitive, with weak velocity sensitivity, strong salt sensitivity, weak alkali sensitivity, and are not acid sensitive. The LN block is of a weak hydrophilic type.
(3)
Oil–water property
The LN block is low in density, low in viscosity, has thin oil (low abundance), an average surface crude oil density of 0.8819 g/cm3, an average surface viscosity of 45.1 mPa·s, and an average freezing point of 22 °C. The water type is CaCl2; salinity is 55,965.5 mg/L.
(4)
Temperature–pressure system
With a pressure coefficient of 1.03 and a temperature gradient of 3.54 °C/100 m, the reservoir of the Shasi belongs to a normal pressure and normal temperature system.
(5)
Sand body distribution
Log interpretation 17# of the CS6 sand group in well LN-1 has a large lateral change, with well LN-3 pealing out and well LN-5 thinning. And, logging interpretation 22# has a relatively good lateral stability as shown in Figure 2.
(6)
Reservoir stress analysis
According to the calculation results of reservoir stress, the reservoir stress is 56–58 MPa, the ground stress of the upper spacer is 63–65 MPa, the ground stress of the lower spacer is 65–66 MPa, and the stress difference between the reservoir and the spacer is 6–7 MPa. The spacer can play a good role in blocking the pressure fracture height and meeting the requirements of layered fracturing.

2.1.4. Logging Map of the LN-1 Well

The target layer of this reconstruction is the two layers of electrical interpretation 17# and 22#. The upper interval of layer 17# is 16 m for the water layer, and the lower interval of layer 22# is 8 m for the fractured layer, as shown in Figure 3.
The red curve represents induced conductivity, CILD (mS/m). The green curve represents the gradient resistivity at the bottom of 50 m, VR50 (Ω·m). The blue curve in the middle represents the natural potential, SP (mv). The bottom blue and red curves represent deep and shallow lateral resistivity, RD and RS, respectively.

2.2. Fracturing Difficulties of the LN Block

2.2.1. Analysis of the Adjacent Well Fracturing Situation

By comparing the fracturing parameters of adjacent wells in the same LN block, it can be seen that the effect of staged fracturing is better than that of general fracturing. Fracturing well parameters in the LN block are shown in Table 1.
On 17 March 2012, the 23#–28# of well LN-1 were constructed by the general fracturing method. The construction displacement was 5.1 m3/min, the 0.212 mm–0.425 mm ceramic sand was 20.0 m3, the 0.425 mm–0.85 mm ceramic sand was 60.0 m3, and the rupture pressure was 58.1 MPa. Construction pressure was 36–58.1 MPa, and the stop pump pressure was 23.7 MPa. After pressure effect: 3 mm nozzle self-injection, daily fluid 4.7 t, daily oil 2.3 t, water content 51% (return period). On 1 May 2012, the initial production was 8.5 t/d liquid, 5.4 t/d oil, and 25.9% water. By March 2018, the production was 1.1 t/d liquid, there was 1 t/d of oil, and cumulative oil and water yield were 3756 t and 851 t, respectively.

2.2.2. Fracturing Difficulties of the LN-1 Well

(1)
Poor material foundation was identified for the LN-1 well, and we encountered difficulty in stabilizing production after fracturing. This area is a deep low-abundance oil reservoir, and its productivity shows the declining law of typical low-permeability reservoirs. The initial production is high, the decline is fast, the natural energy of the reservoir is insufficient, the pressure drop is fast, and the annual decline rate of elastic development is 36.4~40.2%.
(2)
The effect of conventional fracturing process reform is poor. The well 23#–28# adopted the general fracturing process and produced 3756 t of oil in 6 years after fracturing. The longitudinal span of the reservoir is large, the difference between layers is large, the adaptability of large-scale general fracturing is poor, and the effective communication and transformation of each layer cannot be guaranteed.
(3)
Stage fracturing has achieved a certain stimulation effect, but when limited by the scale of fracturing reconstruction, the stimulation effect is poor. According to the fracturing effect of multiple intervals in adjacent oil wells, it is concluded that under the condition that the thickness of the reservoir and the amount of sand added are not different, the multi-stage fracturing shows a better oil increase effect. In the LN-5 well with the same sand body as this well, the CS6 effective thickness is 10.2, and sand body thickness is 18.3 m, and the sand addition is 25 m3. The fracturing scale is small, which has a certain impact on the later production capacity.
(4)
The reservoir in this block has moderate water sensitivity and a pressure coefficient of 1.03, which is not conducive to the flowback of fracturing fluid after fracturing.
(5)
The thickness of the reconstructed sand body is large, and the well-logging data show that the sand body is highly different. It is necessary to consider the influence of perforation sweet spot selection and proppant settlement in the fracture on the flow conductivity.

3. Key Technology of Fracturing Stimulation in the LN-1 Well

The target layer of this fracturing has a span of 62 m, and the general fracturing reform is poorly targeted. The layered fracturing process is adopted to carry out layered fracturing for 17# and 22#. Limited by the casing head pressure of 35 MPa, the oil pipe + packer is used to fracture. According to the characteristics of this well and the fracturing situation of adjacent wells, the fracturing reconstruction technology of this well is optimized.

3.1. New High-Efficiency Stimulation Fracturing Fluid System

3.1.1. Reason for Adoption

The shale content of 22# in this well is 23.16% (among which, the illite/montmorillonite (I/S) formation is 36%), with weak to moderate water sensitivity and a pressure coefficient of 1.03, which is not conducive to fracturing fluid flow back. Therefore, the fracturing fluid system needs to be optimized to reduce fracturing fluid damage [30,31,32,33].
Through the optimization of the fracturing fluid system, it can not only meet the fracture-forming and sand-carrying performance of the fracturing fluid, but also change the reservoir wettability, so that a large number of remaining oil can be driven out to significantly reduce the damage degree of the reservoir and greatly improve the effect of fracturing reform.

3.1.2. New High-Efficiency Stimulation Fracturing Fluid System

(1)
The penetration capacity of aqueous active substances is improved [34,35] through nano- and microemulsion and other technical means to ensure that the active substances which penetrate the oil layer reach the pore matrix and reduce adsorption losses.
(2)
The reservoir rock wettability is changed. By reducing the adsorption of crude oil on the rock surface and changing the surface wettability, the water-phase capillary force is enhanced, the self-imbibition rate is increased, the existing oil/water balance is broken, and crude oil production is increased.

3.1.3. Optimization of Discharge Aid

The conventional drainage aid system and the high-efficiency drainage aid system with SD-20 were kept at a constant temperature of 235 °C for 14 days, and the amount of water removed from the drainage aid was measured at 500, 700, 800, 1000, and 1500 rpm, respectively, to calculate the water loss rate. According to the results of the indoor core dehydration test (as shown in Figure 4), the water loss rate of the system supplemented with SD-20 efficient drainage aid is 15–19% higher than that of the conventional system, indicating that it has better flowback performance. According to the results of the flowback test under indoor high-temperature conditions, after two weeks of heat treatment at 235 °C, the product shows almost the same flowback capacity as the product without superheating treatment, indicating that it has good thermal stability.

3.1.4. Surfactant Optimization

The oil production effect of 2% KCl solution with GS-1080 and GS-256 added is more obvious, as shown in Figure 5. When the solution contains a small amount of GS-1080 (0.3%) and GS-256 (0.3%), the core oil yield increases significantly. For the GS-1080-soaked core, the oil yield continued to increase, and when soaked 30 days after the core surface was clean, no residual oil droplets were found in the bottle; oil yield increased up to 46.53%, and the washing effect was good. Among the three soaked cores, the core soaked by GS-1080 has the lowest permeability and the highest oil yield. In summary, GS-1080 has the best oil washing effect.
This fracturing fluid system is optimized to have the following characteristics:
(1)
It meets the fracturing fluid fracture-making and sand-carrying performance requirements.
(2)
It can effectively reduce the resistance brought by the adsorption force of fracturing residual fluid.
(3)
It has lower surface tension and effective change in wettability.
(4)
It effectively helps to clean the residual oil adsorbed in the rock.
(5)
In this research, the added efficient discharge aid and surfactant do not contain fluorocarbon, environmental protection, and are pollutant-free.

3.2. Cluster Perforating Process

According to the well log, the 17# sand body of the well LN-1 is relatively pure, but the 22# sand body is interpreted as the dry layer below the upper oil layer. The microelectrode curve in the layer fluctuates greatly, indicating that the sand body in this layer is not pure. The results of the in situ stress calculation show that the stress in the upper part of layer 22# is 58.2 MPa and the stress in the lower part is 62 MPa, with a difference of about 4 MPa. If the concentrated perforation method is used, the fracture will extend to the low-stress area, and the reconstruction effect of the lower reservoir is poor.
Therefore, the cluster perforation process was adopted for layer 22# to select sandstone sections with high resistivity, low density, and low stress, and take into account the longitudinal extension of fractures to optimize the perforation location for the purpose of maximizing reservoir utilization [36,37].

3.3. High Diversion Channel Fracturing

3.3.1. Reason for Adoption

(1)
To reduce the proppant settling rate, improve the proppant placement effect in the fracture, and increase the propping fracture height.
(2)
To change the “surface” support to “point” support, greatly improving the fracture conductivity.
(3)
The amount of proppant in high-speed channel fracturing is about 70% of that in conventional processes, saving construction costs.

3.3.2. Fiber Optimization

The fiber system suitable for channel fracturing was screened through the experiments of fiber dispersibility, sand carrying, sand stabilization, compatibility, etc. According to the results of the laboratory evaluation, the GHHX-6 biodegradable fiber system was selected. The fiber length is 8–9 mm, and the optimal fiber dosage is 0.5–0.7% of the proppant weight.

3.4. Temporary Plugging to Fracturing Technology

3.4.1. Reason for Adoption

(1)
Temporary plugging in the joint can form complex cracks. The sand body of the target layer is thinned to the east and west and peaked out in the northwest direction of 17# (shown in Figure 2). If a single long fracture is formed in this kind of reservoir, the stimulation effect is limited. By adopting the process of in-seam temporary plugging, the cracks are forced to form complex cracks, and the spread width of the crack system is increased to improve the transformation effect [38,39].
(2)
The inter-cluster (layer) temporary plugging technology can improve the uniformity of reservoir longitudinal reconstruction. Layer 17# uses centralized perforation, which does not require temporary inter-cluster plugging. The physical properties of layer 22# are very different, and there is a stress difference of about 4 MPa. In the construction, the low-stress part is pressed open first. If no temporary plugging is carried out, the majority of fracturing fluid may enter the low-stress layer, while the high-stress layer does not allow even a small amount of fracturing fluid to enter, resulting in inadequate and uneven transformation.

3.4.2. Temporary Plugging Agent Type Optimization

The purpose of the experiment of selecting the type of temporary plugging agent is to test the weight change (dry weight, and weight after water absorption) of different temporary plugging agents after water absorption and compare their expansion effect, so as to obtain a temporary plugging agent with good plugging performance. The evaluation results of a temporary plugging agent are shown in Figure 6. The temporary plugging agent (CPG-H620) expands sharply and rapidly after encountering water and can expand to 90% of the maximum weight within 30 min, and up to 6 times the original weight, so it can form a filter cake that is airtight with good sealing.
After the selection of the temporary plugging agent, it is necessary to evaluate the dissolution of the temporary plugging agent solution at a certain concentration (such as 1% mass fraction) within a specific temperature and time range, so as to evaluate the dissolution rate of the temporary plugging agent solution. The experimental results of the dissolution rate of the temporary plugging agent (TPA) are shown in Figure 7. The solution containing 1% CPG-H620 was completely dissolved at 70 °C for 24 h. Therefore, CPG-H620 is preferred as the TPA for this construction.

3.4.3. Particle Size Optimization of Temporary Plugging Agent

In this well, temporary plugging in fractures and between zones is required. To achieve different uses, a temporary plugging agent with a diameter of 5–30 mesh is preferred for temporary plugging between layers. A temporary plugging agent with a diameter of more than 60 mesh is preferred for temporary plugging in the fracture.

3.4.4. Optimization of Temporary Plugging Agent Dosage

According to the perforating section length and number of holes, crack size, particle size, concentration of temporary plugging agent, and timing of adding a temporary plugging agent, the optimal interlayer temporary plugging agent dosage is as follows: perforating section is 35–45 kg/m; adding concentration is 30–50 kg/m3. The amount of temporary plugging agent in the layer is 1500–2500 kg/m2 (fracture height × fracture width), and the concentration is 15–30 kg/m3.

4. Construction Process and Effect

The two-layer fracturing was completed on 27 September 2019. As shown in Figure 8a, the first layer, with a fracturing pump displacement of 5 m3/min, added 6 m3 of 40/70 mesh proppant and 49 m3 of 20/40 mesh proppant. Rupture pressure was 57 MPa, construction pressure was 45–55 MPa, stop pump pressure was 22 MPa, and 390 kg of fiber was added in this process.
The second layer is shown in Figure 8b. On 27 September, at a displacement of 4 m3/min, 6 m3 of 40/70 mesh proppant and 39 m3 of 20/40 mesh proppant were added. The rupture pressure was 68 MPa, the construction pressure was 45–60 MPa, the pump stop pressure was 22.5 MPa, and 280 kg of fiber was added in this process.
The mechanical layering, the fiber + pulse sand fracturing method, was used to complete the two-stage fracturing construction; the construction process was smooth, and the designed sand addition amount was completed. The in-fracture temporary plugging agent and interlayer temporary plugging agent have an obvious pressure rise each time they are added, which has the effect of sealing the old seam and increasing the net pressure in the fracture to open the new fracture. After fracturing, the LN-1 well was discharged with a 3 mm nozzle and began producing oil on the third day of discharge. The initial fluid production of the well was 16.5 t/d, the oil production was 13.6 t/d, and the cumulative oil production was 105 t through flowing. After sand pumping production, the production liquid was 14.3 t/d; there was 12.5 t/d of oil, and the water content was 12%. The average oil production after pressure in adjacent wells was 8.3 t/d, and the 23–28# after pressure in well LN-1 was also CS6; the oil accumulation was 5.4 t/d, and the production after pressure in this well was higher than that in adjacent wells. The fracturing stimulation series technology used has been successful.

5. Conclusions

(1)
Laboratory experiments show that the new high-efficiency stimulation fracturing fluid flowback rate is 15–19% higher than the conventional fracturing fluid system, and the oil washing efficiency is 46.5%. The new high-efficiency stimulation fracturing fluid system has the effect of low damage, changing oil reservoir wettability, and has better adaptability to this kind of oilfield with low natural energy and water sensitivity.
(2)
According to the temporary plugging and turning fracturing process optimized at the spread point of the sand body in well LN-1, obvious pressure rise was seen in each addition of the temporary plugging agent in the middle fracture and the interlayer temporary plugging agent, which played a role in sealing the old fracture and increasing the net pressure in the fracture to open the new fracture.
(3)
The LN block is a low-abundance and greater-depth reservoir with weak natural energy and elastic development, and the conventional fracturing effect is poor. The new fracturing stimulation series technology has achieved good test results in the well LN-1, which can provide technical guidance for the efficient development of low-abundance, deeper, and difficult-to-develop oil reservoirs.
The above points are concluded mainly based on the obtained geology and development data of the LN block, which may not be sufficient, and so, more research involving different oil reservoirs (geological characteristics and development bottleneck) is needed in the future to obtain a full picture of the fracturing technique.

Author Contributions

Conceptualization, M.S. and D.C.; methodology, M.S. and D.C.; validation, M.S. and T.W.; formal analysis, L.W. and T.W.; investigation, L.W. and W.S.; resources, M.S.; data curation, W.S. and J.W.; writing—original draft preparation, M.S. and L.W.; writing—review and editing, D.C. and L.W.; project administration, T.W. and J.W. All authors have read and agreed to the published version of the manuscript.

Funding

This research was funded by the Innovation fund project for graduate student of China University of Petroleum (East China), the Fundamental Research Funds for the Central Universities (23CX04050A), the National Natural Science Foundation of China (42202182), and the Natural Science Foundation of Shandong Province (ZR2021ME006).

Data Availability Statement

Data are contained within the article.

Acknowledgments

The authors wish to thank the researchers who provided technical and economic assistance during this study. The authors also express their sincere appreciation to the anonymous reviewers for their valuable and constructive comments.

Conflicts of Interest

The authors declare no conflicts of interest.

References

  1. Zhang, L.J.; Sun, T.W.; Han, X.B.; Shi, J.C.; Zhang, J.S.; Tang, H.T.; Yu, H.Y. Feasibility of advanced CO2 injection and well pattern adjustment to improve oil recovery and CO2 storage in tight-oil reservoirs. Processes 2023, 11, 3104. [Google Scholar] [CrossRef]
  2. Cao, A.Q.; Li, Z.M.; Zheng, L.; Bai, H.; Zhu, D.; Li, B.F. Nuclear magnetic resonance study of CO2 flooding in tight oil reservoirs: Effects of matrix permeability and fracture. Geoenergy Sci. Eng. 2023, 225, 211692. [Google Scholar] [CrossRef]
  3. Bao, M.T.; Kong, X.P.; Jiang, G.C.; Wang, X.L.; Li, X.M. Laboratory study on activating indigenous microorganisms to enhance oil recovery in Shengli Oilfield. J. Pet. Sci. Eng. 2009, 66, 42–46. [Google Scholar] [CrossRef]
  4. Li, C.F.; Li, Y.; Li, X.M.; Cao, Y.B.; Song, Y.T. The Application of microbial enhanced oil recovery technology in Shengli Oilfield. Pet. Sci. Technol. 2015, 33, 556–560. [Google Scholar] [CrossRef]
  5. Cui, Q.F.; Sun, S.S.; Luo, Y.J.; Yu, L.; Zhang, Z.Z. Comparison of in-situ and ex-situ microbial enhanced oil recovery by strain Pseudomonas aeruginosa WJ-1 in laboratory sand-pack columns. Pet. Sci. Technol. 2017, 35, 2044–2050. [Google Scholar] [CrossRef]
  6. Wang, S.; Zhou, J.; Zhang, L.Q.; Han, Z.H. Numerical investigation of injection-induced fracture propagation in brittle rocks with two injection wells by a modified fluid-mechanical coupling model. Energies 2020, 13, 4718. [Google Scholar] [CrossRef]
  7. Wang, B.; Fang, Y.; Li, L.Z.; Liu, Z. Automatic optimization of multi-well multi-stage fracturing treatments combining geomechanical simulation, reservoir simulation and intelligent algorithm. Processes 2023, 11, 1759. [Google Scholar] [CrossRef]
  8. Lu, C.; Ma, L.; Guo, J.C.; Zhao, L.; Xu, S.Q.; Chen, B.G.; Zhou, Y.L.; Yuan, H.R.; Tang, Z.B. Fracture parameters optimization and field application in low-permeability sandstone reservoirs under fracturing flooding conditions. Processes 2023, 11, 285. [Google Scholar] [CrossRef]
  9. Kong, X.W.; Wan, X.; Li, S.; Liu, Z.C.; Chen, M.Z.; Shen, J.W. Experimental evaluation and optimization of improved conductivity of gelling acid etched fractures in deep, low-permeability reservoirs. Fuel 2023, 348, 128468. [Google Scholar] [CrossRef]
  10. Wu, B.L.; Wu, G.A.; Wang, L.; Lou, Y.S.; Liu, S.Y.; Yin, B.; Li, S.Z. Study on fracturing parameters optimization of horizontal wells in low-permeability reservoirs in South China Sea. Processes 2023, 11, 2999. [Google Scholar] [CrossRef]
  11. Cheng, B.Y.; Li, J.J.; Li, J.Q.; Su, H.; Tang, L.H.; Yu, F.W.; Jiang, H.Q. Pore-scale formation damage caused by fracturing fluids in low-permeability sandy conglomerate reservoirs. J. Pet. Sci. Eng. 2022, 208, 109301. [Google Scholar] [CrossRef]
  12. Li, X.; Chen, X.; Xu, Z.H.; Pu, C.S. A novel foam flooding for enhanced oil recovery in fractured low-permeability reservoirs: Performance evaluation and mechanism study. SPE J. 2022, 27, 2408–2424. [Google Scholar] [CrossRef]
  13. Li, N.Y.; Chen, F.; Yu, J.J.; Han, P.H.; Kang, J. Pre-acid system for improving the hydraulic fracturing effect in low-permeability tight gas reservoir. J. Pet. Explor. Prod. 2021, 11, 1761–1780. [Google Scholar] [CrossRef]
  14. Li, N.Y.; Zhu, S.J.; Li, Y.; Zhao, J.R.; Long, B.; Chen, F.; Wang, E.Z.; Feng, W.T.; Hu, Y.N.; Wang, S.B.; et al. Fracturing-flooding technology for low permeability reservoirs: A review. Petroleum 2023, in press. [CrossRef]
  15. Liu, W.C.; Zhang, Q.T.; Zhu, W.Y. Numerical simulation of multi-stage fractured horizontal well in low-permeable oil reservoir with threshold pressure gradient with moving boundary. J. Pet. Sci. Eng. 2019, 178, 1112–1127. [Google Scholar] [CrossRef]
  16. Wang, J.; Xie, H.P.; Matthai, S.K.; Hu, J.J.; Li, C.B. The role of natural fracture activation in hydraulic fracturing for deep unconventional geo-energy reservoir stimulation. Pet. Sci. 2023, 20, 2141–2164. [Google Scholar] [CrossRef]
  17. Guo, T.K.; Gong, F.C.; Shen, L.; Qu, Z.Q.; Qi, N.; Wang, T. Multi-fractured stimulation technique of hydraulic fracturing assisted by radial slim holes. J. Pet. Sci. Eng. 2019, 174, 572–583. [Google Scholar] [CrossRef]
  18. Liu, X.F.; Jia, X.Q.; Niu, Y.; Nie, B.S.; Zhang, C.P.; Song, D.Z. Alterations in coal mechanical properties and permeability influenced by liquid CO2 phase change fracturing. Fuel 2023, 354, 129254. [Google Scholar] [CrossRef]
  19. Liang, T.B.; Wei, D.Y.; Zhou, F.J.; Li, X.H.; Yuan, L.S.; Wang, B.; Lu, J. Field experiments on multi-stage chemical diversion in low-permeability HPHT reservoirs. J. Pet. Sci. Eng. 2020, 187, 106738. [Google Scholar] [CrossRef]
  20. Zhao, L.Q.; Chen, Y.X.; Du, J.; Liu, P.L.; Li, N.Y.; Luo, Z.F.; Zhang, C.C.; Huang, F.S. Experimental study on a new type of self-propping fracturing technology. Energy 2019, 183, 249–261. [Google Scholar] [CrossRef]
  21. Veliev, M.M. Specifics of cyclic water flooding for development systems made up with horizontal wells. Neft. Khoz. Oil Ind. J. 2021, 7, 86–89. [Google Scholar]
  22. Bi, G. Structural design and flow field characteristics analysis of a new spin-on multi-hole jet drill bit for radial horizontal wells. Geoenergy Sci. Eng. 2023, 230, 212173. [Google Scholar] [CrossRef]
  23. Zhang, C.; Song, Z.Y.; Zhao, Y.X. Staged multicluster hydraulic fracture propagation mechanism and its influencing factors in horizontal wells for CBM development. Energy Sci. Eng. 2023, 11, 448–462. [Google Scholar] [CrossRef]
  24. Qi, N.; Chen, G.B.; Liang, C.; Guo, T.K.; Liu, G.L.; Zhang, K. Numerical simulation and analysis of the influence of fracture geometry on wormhole propagation in carbonate reservoirs. Chem. Eng. Sci. 2019, 198, 124–143. [Google Scholar] [CrossRef]
  25. Gao, M.W.; Zhang, M.S.; Du, H.Y.; Zhao, M.W.; Dai, C.L.; You, Q.; Liu, S.; Jin, Z.H. A novel triple responsive smart fluid for tight oil fracturing-oil expulsion integration. Petrol. Sci. 2023, 20, 982–992. [Google Scholar] [CrossRef]
  26. Wu, B.C.; Ma, X.F.; Li, J.M.; Tian, G.; Xiong, D.; Zou, Y.S.; Zhang, S.C. Numerical simulation of fracture propagation of multi-cluster perforation and fracturing in horizontal wells: A case study of Mahu oilfield. Energies 2022, 15, 5579. [Google Scholar] [CrossRef]
  27. Xing, X.S.; Wu, G.G.; Zhou, J.; Zhang, A.S.; Hou, Y.N.; Xie, X.; Wu, J.S.; Kong, X.W.; Li, S. Finite element study on the initiation of new fractures in temporary plugging fracturing. Front. Phys. 2023, 11, 1227917. [Google Scholar] [CrossRef]
  28. Qi, M.; Yang, E.; Liu, Y.; Dong, C.; Chen, X. Research and application of a controllable permeability refracturing technology in a high- water- cut potential layer. SPE Prod. Oper. 2023, 38, 478–489. [Google Scholar] [CrossRef]
  29. Tao, X.J.; Gan, M.Z.; Yao, Z.H.; Bai, J.W.; Yang, M.Z.; Su, G.D.; Zheng, L.H. Enhancing the production of tight sandstone gas well through fuzzy-ball fluid temporary plugging with diverting fractures and water cutting after refracturing in one operation. J. Pet. Sci. Eng. 2022, 217, 110883. [Google Scholar] [CrossRef]
  30. Li, X.J.; Zhang, Q.J.; Liu, P.; Li, T.; Liu, G.F.; Liu, Z.K.; Zhao, H.F. Investigation on the microscopic damage mechanism of fracturing fluids to low-permeability sandstone oil reservoir by nuclear magnetic resonance. J. Pet. Sci. Eng. 2022, 209, 109821. [Google Scholar] [CrossRef]
  31. Chen, M.J.; Yan, M.L.; Kang, Y.L.; Fang, S.D.; Liu, H.; Wang, W.H.; Shen, J.K.; Chen, Z.Q. Shale formation damage during fracturing fluid imbibition and flowback process considering adsorbed methane. Energies 2022, 15, 9176. [Google Scholar] [CrossRef]
  32. Shao, J.X.; You, L.J.; Kang, Y.L.; Chen, M.J.; Tian, J. Salinity of flowback fracturing fluid in shale reservoir and its reservoir damage: Experimental and field study. J. Pet. Sci. Eng. 2022, 211, 110217. [Google Scholar] [CrossRef]
  33. Wang, J.; Huang, Y.; Zhang, Y.; Zhou, F.; Yao, E.; Wang, R. Study of fracturing fluid on gel breaking performance and damage to fracture conductivity. J. Pet. Sci. Eng. 2020, 193, 107443. [Google Scholar] [CrossRef]
  34. Lei, Q.; Yang, Z.W.; Weng, D.W.; Liu, H.T.; Guan, B.S.; Cai, B.; Fu, H.F.; Liu, Z.L.; Duan, Y.Y.; Liang, T.C.; et al. Techniques for improving fracture-controlled stimulated reservoir volume in ultra-deep fractured tight reservoirs: A case study of Kuqa piedmont clastic reservoirs, Tarim Basin, NW China. Petrol. Explor. Dev. 2022, 49, 1169–1184. [Google Scholar] [CrossRef]
  35. Liu, C.; Li, Y.Y.; Wang, P.; Jiao, H.Y.; Yao, X.T.; Zhao, G.; Dai, C.L.; You, Q. Preparation and performance evaluation of nano-composite fracturing fluid with good oil displacement ability in tight reservoir. J. Mol. Liq. 2022, 367, 120494. [Google Scholar] [CrossRef]
  36. Guo, X.Q.; Liu, J.; Du, Z.G.; Tang, K.; Cao, D.Y.; He, Z.Q. Mechanical characteristics of cluster perforation string under running process in horizontal wells with unconventional oil/gas reservoirs. SPE. Prod. Oper. 2022, 37, 664–680. [Google Scholar] [CrossRef]
  37. Fan, Q.H.; Ma, Y.G.; Wang, J.P.; Chen, L.; Ye, Z.Q.; Xu, Y.J.; Li, H.; Wang, B. Investigation into the perforation optimization in conglomerate reservoir based on a field test. Processes 2023, 11, 2446. [Google Scholar] [CrossRef]
  38. Zhong, Y.; Zhang, H.; Feng, Y.H.; Li, J.L.; Yang, Y.; She, J.P. A composite temporary plugging technology for hydraulic fracture diverting treatment in gas shales: Using degradable particle/powder gels (DPGs) and proppants as temporary plugging agents. J. Pet. Sci. Eng. 2022, 216, 110851. [Google Scholar] [CrossRef]
  39. Wang, Y.; Zhou, C.L.; Yi, X.Y.; Li, L.; Chen, W.H.; Han, X. Technology and application of segmented temporary plugging acid fracturing in highly deviated wells in ultradeep carbonate reservoirs in Southwest China. ACS Omega 2020, 5, 25009–25015. [Google Scholar] [CrossRef]
Processes 12 00482 g001
Figure 1. Structural diagram of the LN-1 well.
Figure 1. Structural diagram of the LN-1 well.
Processes 12 00482 g001
Processes 12 00482 g002
Figure 2. Near east–west reservoir profile of Shasi. The black curve represents the natural potential, SP; the blue curve represents true formation resistivity, RT.
Figure 2. Near east–west reservoir profile of Shasi. The black curve represents the natural potential, SP; the blue curve represents true formation resistivity, RT.
Processes 12 00482 g002
Processes 12 00482 g003
Figure 3. Logging map of the LN-1 well.
Figure 3. Logging map of the LN-1 well.
Processes 12 00482 g003
Processes 12 00482 g004
Figure 4. Results of core dehydration test.
Figure 4. Results of core dehydration test.
Processes 12 00482 g004
Processes 12 00482 g005
Figure 5. Experimental results of core flooding.
Figure 5. Experimental results of core flooding.
Processes 12 00482 g005
Processes 12 00482 g006
Figure 6. Experimental results of expansion coefficient of TPA.
Figure 6. Experimental results of expansion coefficient of TPA.
Processes 12 00482 g006
Processes 12 00482 g007
Figure 7. Experimental results of dissolution rate of TPA.
Figure 7. Experimental results of dissolution rate of TPA.
Processes 12 00482 g007
Processes 12 00482 g008
Figure 8. Fracturing construction curves.
Figure 8. Fracturing construction curves.
Processes 12 00482 g008
Table 1. Fracturing parameters of the LN block.
Table 1. Fracturing parameters of the LN block.
WellModified HorizonTimePerforation Thickness (m)Span (m)Sand Addition (m3)Sand Strength (m3/m)Daily Fluid Production (t)Daily Oil Production (t)Number of Stages
LN-4CX12008.116.51426.31.98.57once
LN-1CS62012.052132.6802.58.45.4once
LN-5CX1+22012.0214.614.9604.05.03.1once
LN-5CS62012.10929.1652.213.37.8Tier 2
LN-3CX1+S62012.121217.675.44.31413.1Tier 4
Disclaimer/Publisher’s Note: The statements, opinions and data contained in all publications are solely those of the individual author(s) and contributor(s) and not of MDPI and/or the editor(s). MDPI and/or the editor(s) disclaim responsibility for any injury to people or property resulting from any ideas, methods, instructions or products referred to in the content.

Share and Cite

MDPI and ACS Style

Shi, M.; Chen, D.; Wang, L.; Wang, T.; Song, W.; Wang, J. Research and Applications of New Fracturing Technology in Low-Abundance and Greater-Depth Well LN-1 Reservoirs. Processes 2024, 12, 482. https://doi.org/10.3390/pr12030482

AMA Style

Shi M, Chen D, Wang L, Wang T, Song W, Wang J. Research and Applications of New Fracturing Technology in Low-Abundance and Greater-Depth Well LN-1 Reservoirs. Processes. 2024; 12(3):482. https://doi.org/10.3390/pr12030482

Chicago/Turabian Style

Shi, Minghua, Dechun Chen, Liangliang Wang, Tengfei Wang, Wei Song, and Jiexiang Wang. 2024. "Research and Applications of New Fracturing Technology in Low-Abundance and Greater-Depth Well LN-1 Reservoirs" Processes 12, no. 3: 482. https://doi.org/10.3390/pr12030482

APA Style

Shi, M., Chen, D., Wang, L., Wang, T., Song, W., & Wang, J. (2024). Research and Applications of New Fracturing Technology in Low-Abundance and Greater-Depth Well LN-1 Reservoirs. Processes, 12(3), 482. https://doi.org/10.3390/pr12030482

Note that from the first issue of 2016, this journal uses article numbers instead of page numbers. See further details here.

Article Metrics

Back to TopTop