No abstract

In 2016, the gas monobore-completion wells were executed P&A as a pilot campaign to evaluate the technical feasibility and cost in the PTTEP’s setting. By following DMF’s guideline and PTTEP’s regulation, the cement bullheading uses as a method to isolate all hydrocarbon strata up to 30 m above the previous casing shoe. The gas-tight cement recipe is specifically designed for each well condition, then tested in the laboratory and approved by PTTEP prior proceeding the operation. After pumping job, the well shut-in for cement curing and developing strength. The cement must achieve the hydro test at 2,500 psi surface pressure. Otherwise, the contingency plan must be applied i.e. set two metal plugs above the topmost perforation and cover with 30 m of dumped cement. In the first two wells, the pumping operations were completed as plan but failed the hydro test even surface samples had cured and shut-in longer than the testing time in the lab. The re-injectivity test was performed but not enough to redo cement bullheading. The contingency plan was applied to regain well integrity for P&A. It spent an extra 2 days and 100k USD per well. After revisited the cement design, the cause of failure is suspected by the temperature criterion in cement’s testing. Previously, the cement was tested in bottom hole static temperature (BHST) of the bottommost perforation which 45 °C higher than the BHST at the topmost perforation. It is possible that the cement at the top of perforation had not developed sufficient strength prior the test. Hence, the cement’s design criteria are revised. The UCS/UCA tests in BHST at the top perforation while the rest test in bottom hole circulating temperature (BHCT). The lab test reveals that cement rheology is quite thick but still pumpable. Furthermore, some wells require to shut-in up to 3 days before gaining the strength. So, the shut-in period after pumping is customized according to the lab test result. After applying this approach in 17 wells, 100% of cement bullheading jobs achieve the surface test and no need to apply the contingency plan. This contributes the cost saving 1.7 MMUSD over the campaign. There are approximately 400 wells of PTTEP in the Gulf of Thailand that have high-temperature gradient and long reservoir section. These wells exactly require this approach to get success in cement bullheading, so the potential cost saving based on the previous price is about 40 MMUSD in the future.

The artificial lift selection process performed by human involves iterating of several design parameters. Moreover, the human's curated selection required the decision making with unbiased, repeatable and reliable. Capturing the lesson learned from the previous mistake into the new design and lack of look back in the past performances are the limits of human. The supervised machine learning method can apply to improve selection process. This approach can minimize the life-cycle cost of artificial lift wells by using machine learning which incorporate the past performances and lesson learnt from installations. The data is prepared into a structured dataset. The dataset is pre-processed to determine the "Good" and "Bad" wells based on their life-cycle cost, then used for training and validating the classification models. The most simple and accurate model is adopted for future artificial lift selection and current wells’ performance assessment. Finally, the performance of new wells is continuously added for further model's training. The artificial lift suggested by the machine learning expects reducing life-cycle cost in the ongoing trial in the fields. In term of assessing tool, the selection model reveals some discrepancy in the current installed artificial lift. This alerts the operator to look inside the potential problems. However, the subject matter experts still need to give an adequate interaction in case of false alarm. Therefore, the discovered pattern for good artificial lift selection will help improve the fields’ production. In addition, the endless learning capability of machine learning allows the new data feeds into the existing dataset and further incorporates the model in order to response to the dynamic change of the fields’ conditions. In conclusion, machine learning process is more comprehensive comparing to the selection made by conventional process where only few tables used for the artificial lift selection and overlook the value of data captured. The Artificial Intelligence is one of the emerging technologies which provides the breakthrough results. This paper presents the artificial intelligence trend in oil and gas industry. It is a promising tool which help solving human's complex problems. Ultimately, adding the durable competitive advantage to the oil and gas industry.

During most hydraulic fracturing operations, coiled tubing (CT) is used as a contingency option for well cleanup in the case of sand screenout. An alternative improvised solution is presented introducing a single-shot circulating valve into the frac string to help minimize additional resources related to CT procedures, thus reducing costs and enhancing operational performance. The tool is positioned above the retrievable frac packer to provide circulation capability to reverse out proppant sand without well intervention activities. Setup, operating procedures, concept evaluation, and performance of the single-shot circulating valve used to reverse proppant sand from the frac string are discussed. A single-shot circulating valve in the frac string provides additional liquid flow pass for recovering excess sand inside the frac string to the surface. Intensive laboratory testing was performed to evaluate tool function in worst-case scenarios of a highly deviated well with proppant sand packed above the circulating ports. During field operations, activated pressure tolerance was defined by incorporating rupture-disk reliability and temperature decrement effects during hydraulic fracturing to help ensure the operating pressure did not impair the fracturing operation or well integrity. Lastly, a cleanout procedure was meticulously planned to help prevent pipe sticking situations caused by sand fallout in the annulus. The single-shot circulating valve, typically deployed during drillstem testing (DST) operations, proved successful circulating out the proppant-sand column packed inside the tool during both laboratory testing and field operations. With precise hydrostatic pressure calculations, the burst pressure was reliable, meaning no premature activation occurred, and the rupture-disk burst within the designed surface pressure tolerance of ±400 psi. During reverse circulation, pumping pressure was maintained within an acceptable range (the maximum pumping rate across the circulating ports was 8 bbl/min) and no visual tool damage occurred. Deploying comprehensive engineering and operating procedures (e.g., defining the operating envelope to maintain a higher casing pressure than drillpipe pressure), the frac string and retrievable downhole frac packer were free of sand and successfully retrieved, even during a screenout scenario. Based on the success of the prolonged two-year fracturing operations, the proposed approach is appropriate for fracturing using a single-shot circulating valve as the primary contingency equipment during screenout, replacing CT intervention for this application. This alternative method resulted in improved safety and operational efficiency by eliminating on-rig CT operations when screenout pressure is trapped in the string in addition to significant cost savings attributed to eliminating the extra standby resources of a CT package. This innovative approach, which applies functions of a downhole well-testing tool during hydraulic fracturing, requires both circumspect engineering consideration to define a proper operating envelope and comprehensive operational procedures to help mitigate operational risks.

This paper aims to elaborate the strategy for operational and cost efficiency improvement by providing an example of a successful case of rig selection strategy for Hydraulic Fracturing Operation in S1 oil field Thailand. The integrated workflow proposed involves all concerned parties to specify the scope of work, analyze internal and external strengths and weaknesses, evaluate possible scenarios, and identify the procurement strategy. As a case of rig selection for fracturing operation in the heterogeneous sandstone, committing the number of candidates before drilling is impossible. Therefore, the typical criteria for fracturing rig selection consider rig move mobility and flexibility in candidate selection. However, in a proven area, the uncertainty of candidate confirmation is manageable. Reservoir engineers provide the number of candidates in 3 scenarios for sensitivity analysis. SWOT analysis and the market survey reveal the possibility to improve both performance and cost by using a warm-stack skidding rig instead of a truck-mounted rig. The sensitivity analysis by using the historical data of each type, indicates that the number of candidates and rig cost play a significant role in cost saving. As a result of analysis and strategy, the operation performance improvesby 34% (2 months reduction) leading to cost-saving by 1MM USD or 24% of the time-dependent cost.