Pressure monitoring and diagnostics at the surface could help operators understand whether their fractures are behaving as planned.
A Chinese operator tested whether wellhead high-frequency pressure monitoring combined with diagnostics offered a low-cost option for evaluating fracturing stages across unconventional fields, as compared to methods like fiber optics and downhole video.
While presenting SPE 228229 at SPE’s Annual Technical Conference and Exhibition in Houston in October, Jiutao Wang, director of the management office of the oil and gas research institute at Intercontinental Strait Energy Technology Co. Ltd., said the technique was used to characterize near-wellbore fractures, assess horizontal wellbore integrity, and more at a shale-oil site in the Sichuan Basin.
The monitoring pilot project was conducted on a well with 180-cluster perforation and 38-stage pumping jobs, with pressure data sets recorded during fracturing using high-frequency pressure gauges. The wellhead-connected gauges had a maximum sampling frequency of 4,000 Hz, a maximum pressure rating of 140 MPa, and continuous recording capability of up to 30 days, according to the paper.
“What's the purpose of this data, of this work? We just want to identify propagation efficiency and also the diverter effectiveness,” Wang said.
Monitoring identified abnormal pressure drops in some bridge plugs, enabling the operator to quantitatively evaluate parameters of near-wellbore fracture networks within the reservoir.
The method is an alternative to traditional approaches like permanent optical fiber, downhole video, chemical tracers, and microseismic, which may offer high precision and efficiency but have higher costs and deployment risk, Wang said.
High-frequency wellhead-pressure-monitoring technology (Fig. 1) is easy to install and requires no downhole intervention, which translates into low operational risks and costs, he said. The high-frequency pressure sensor collected real-time, high-frequency pressure data during fracturing, shutdown, and flowback periods.
The approach raises a few challenges, including the need for large volumes of validated pressure data sets and lengthy computational cycles that make it difficult to provide rapid on-site diagnosis and evaluation, the paper’s authors wrote. To address those issues, the team used an integrated approach that combining tube-wave governing equations, cepstrum analysis (signal-processing methods), and noise-reduction filtering techniques.
“The basic theory of this method we based on the water-hammer wave effect. We do some analysis of the water-hammer wave effect after the fracturing,” Wang said.
The team tested the approach on a deep shale-oil well in Sichuan Basin in southwest China. The target reservoir had a vertical depth of about 2,800 m, formation pressure around 50 MPa, and temperature of 88°C. Reservoir porosity ranged from 1.3 to 4.3%, and oil saturation was between 0.5 and 2.5%. The horizontal wellbore’s 1,790 m-length maintained nearly 100% reservoir contact (Fig. 2).
The well was fractured using plug-and-perf with dissolvable plugs for interstage isolation and to address the issue of partial fracture propagation, the authors wrote (Fig. 3).
Across the 38 stages, there were 180 clusters. Stage lengths were between 32 and 59 m long, and configurations were four clusters and six clusters per stage. Temporary plugging balls were used in 14 stages, 84 clusters, and 588 perforations. Because perforation erosion was expected to exceed that of other conventional wells, the operator used 346 dissolvable balls that had a hollow structure and were a symmetrical, conical shape. According to the paper, on-site operations validated the feasibility of pumping temporary plugging balls at high rates. After the fracturing operation, the well was shut in for at least 25 days to maximize the effective stimulated reservoir volume.
Stage 23
The stage 23 design called for using 24 low-density dissolvable plugging balls. Once they were pumped, the surface monitoring system indicated 13 MPa of continuous pressure increase, proving the technical performance of these balls in the field. Pressure-drop analysis indicated cluster efficiency and uniformity in stage 23 were better than stages without diversion, the authors wrote (Fig. 4).
The operation enabled the expansion of the effective stimulated reservoir volume in that stage around the wellbore. The analysis concluded that the production-contributing rate of long, straight fractures was about 59%, compared to 41% of branch fractures from the post-frac assessment, the authors wrote. Finally, post-frac formation pressure showed an 8% increase, contributing to shale-oil displacement throughout the well’s productive life, they added.
Stage 13
Wang said stage 13 recorded a sudden pressure decrease during fracturing. The remote monitoring and control center thought the pressure drop was caused by a bridge-plug slip, bridge-plug leakage, or damage to the annular cement sheath. On-site analysis ruled out the cementing operation, with the authors concluding the issue was most likely caused by leakage bypassing the bridge plug during the stage 13 fracturing operation, rather than by problems with the cement sheath.
They added, “The operator was still able to indirectly diagnose and find the factors contributing to the operational issue using high-frequency wellhead-pressure-acquisition and response-analysis technology.”
Stage 28
Local pressure fluctuations in stage 28 during fracturing differed from variations in other stages. The diversion job was good, Wang said, and pressure analytics confirmed that four perforation clusters were effectively opened and injected with fluid and proppant. Based on water-hammer-pressure waveform signals and other data, the team identified a wellbore integrity issue. “The cementing job is bad,” he said.
The Future
Wang said the pilot project successfully validated the use of the method in terms of determining perforation-cluster efficiency, isolation effectiveness of the dissolvable plugs, and wellbore integrity.
He said the wellhead high-frequency pressure monitoring and diagnostics technique offers the advantages of low cost and high reliability when compared to other existing technologies for monitoring fracturing operations.
The authors said the low cost and high reliability of the approach means it could be easily scaled for widespread application in unconventional fields.
Getting there, Wang said, will require reaching a higher technical readiness level. The authors noted it will also require better denoising methods, better surface instruments with longer lifespans, and robust pressure sensors capable of active signal transmission and passive signal acquisition.
It will also benefit from enhancements that enable it to carry out real-time analysis during fracturing operations without requiring a pump shutdown, they wrote.
“By inputting real-time data such as pressure, pumping rate, and sand concentration ratio into this system, real-time warnings for incidents such as sand plugging or fracture interference will be available in the field,” they added.
For Further Reading
SPE 228229 Cost-Efficient Fracturing Diagnosis Using High-Frequency Wellhead Pressure Response Analysis: Case Study on Shale-Oil Recovery by Z. Tong, Research Institute of Petroleum Exploration & Development, PetroChina; J. Wang, Intercontinental Strait Energy Technology Co.; X. Deng, China Southern Petroleum Exploration & Development Corp.; J. Tang and Q. Sun, Research Institute of Petroleum Exploration & Development, PetroChina; Y. Fan, China National Logging Corporation Daqing Branch; and M. Che and D. Jia, Research Institute of Petroleum Exploration & Development, PetroChina.
