The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
- Data Science & Engineering Analytics
The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
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Al-Obaid, Hashem (Saudi Aramco, Dhahran, Eastern Province, Saudi Arabia) | Al-Mulhim, Bassam (Saudi Aramco, Dhahran, Eastern Province, Saudi Arabia) | Ashby, Scott (Saudi Aramco, Dhahran, Eastern Province, Saudi Arabia) | Alyousef, Abdulmuin (Completion Energy, Dhahran, Eastern Province, Saudi Arabia)
Abstract Plug and perf technique is a common method to unlock the potential of tight gas formations. The conventional method is to set millable plugs to establish zonal isolation between target stages. A new degradable frac plug has been introduced for high pressure and high temperature applications in sandstone formations plug and perf hydraulic fracturing operations. The development and deployment of the degradable frac plugs that are capable of holding 32 hours of targeted pressure to optimize the cost and time of the conventional well intervention in tight gas reservoirs in Saudi Arabia is presented in this paper. In conventional plug and perf stimulation operations each plug is milled out via coiled tubing. This process increases operational risk and cost associated with multiple downhole trips. Another challenge is wellbore accessibility post stimulation operations. Without changing the fracturing design, two degradable plugs in a three-stage well were deployed. Downhole conditions presented significant challenges including high temperatures of 285 F and pressures. By using a degradable plug, post-frac interventions can be eliminated as the entire plug will degrade in downhole conditions. This would allow the well to be brought online faster than a conventional method would allow. Operational challenges have been experienced during the first deployment of the plug. The plug has successfully held pressure for 32 hours while being exposed to wellbore fluids, which is one of the longest times achieved for a degradable frac plug. One of the main reasons of such success is that the plug is composed of high-grade material. While the plug maintained its integrity for 32 hours in high pressure, it degraded to fine particles post frac operations. Furthermore, the plug was trial tested without affecting the stimulation goals or the overall operation for such well. On this trial test, the plug has shown the ability to eliminate HPCT trips and the associated risks of HPCT intervention. To confirm dissolution of the plugs, an assessment CT run was performed and confirmed shallower plug was not dissolved after 32 hours while the deeper plug already dissolved. With the spread of plug and perf technology on a global level and the increase of horizontal multistage stimulation methods, it is important to capitalize on fit for purpose technologies versus a one-size fits all approach. To address the challenges associated with longer laterals and increasing stage counts, degradable plug technology can be used to improve well economics and reduce associated risks. The elimination of mechanical intervention is the next breakthrough in efficiency gains to increase laterals and achieve higher stage counts.
Guan, Xu (Exploration and Development Research Institute of PetroChina Southwest Oil & Gasfield Company, Chengdu, China) | Zhu, Deyu (Exploration and Development Research Institute of PetroChina Southwest Oil & Gasfield Company, Chengdu, China) | Tang, Qingsong (PetroChina Southwest Oil & Gasfield Company, Chengdu, China) | Wang, Xiaojuan (Exploration and Development Research Institute of PetroChina Southwest Oil & Gasfield Company, Chengdu, China) | Wang, Haixia (Exploration and Development Research Institute of PetroChina Southwest Oil & Gasfield Company, Chengdu, China) | Zhang, Shaomin (Exploration and Development Research Institute of PetroChina Southwest Oil & Gasfield Company, Chengdu, China) | Deng, Qingyuan (Exploration and Development Research Institute of PetroChina Southwest Oil & Gasfield Company, Chengdu, China) | Yu, Peng (Exploration and Development Research Institute of PetroChina Southwest Oil & Gasfield Company, Chengdu, China) | Yu, Kai (Exploration and Development Research Institute of PetroChina Southwest Oil & Gasfield Company, Chengdu, China) | Huang, Xingning (Downhole service company of Xibu Drilling Engineering Company Limited, Karamay, China) | Xu, Hanbing (CNPC, International HK LTD Abu Dhabi, Abu Dhabi, UAE)
Abstract In recent years, tight sandstone gas as one of the important types of unconventional resources, has been rapid explored and developed. There are large-scale tight sandstone gas production in Sichuan Basin, Ordos Basin, Bohai Bay Basin, Songliao Basin and other basins, and it has become a key part in the area of increasing gas reserves and production in China. Due to the influence of the reservoir characteristics, tight gas reservoirs have low porosity and permeability, and the tight gas can only be effectively developed by improving the conductivity around the wellbore. Therefore, it is required to perform hydraulic fracturing after the completion of horizontal well drilling to improve the permeability of reservoir. It can be seen that hydraulic fracturing is the core technology for efficient development of tight gas resources. The implementation of hydraulic fracturing scheme directly determines the horizontal well production and EUR. This paper describes the workflow of 3D geomechanical modeling, technical application for Well YQ 3-3-H4 reservoir stimulation treatment, and carries out hydraulic fracture propagation simulation research based on 3D geomechanical model. This paper also compares the micro-seismic data with the simulation results, and the comparison results show that the propagation model is consistent with the micro-seismic monitoring data, which verifies the accuracy of the model. This paper clarifies the distribution law of hydraulic fractures in the three-dimensional space of horizontal wells in YQ 3 block, and the research results can be used to provide guidance and suggestions for the optimization of fracturing design of horizontal wells in tight gas of Sichuan Basin.
Summary This paper presents a generalized methodology for hydraulic fracturing pump schedule (PS) optimization to maximize a stated objective function. The methodology is illustrated using an example where the objective function of interest is return on investment (RoI) of a single planar fracture in a horizontally layered tight gas reservoir. The method considers both deterministic optimization and optimization under uncertainty with a stepwise solution and the core algorithms described. The resultant PS is operationally realizable, and the results are compared against a base case. Introduction Maximizing returns is the objective of any fracture design, be it economic, recovery, or otherwise. This paper presents a generalized methodology for maximizing financial return and is demonstrated using an example to optimize a single planar fracture such that RoI, at 1 year, is maximized. The paper does not discuss the nature of the fracture modeling itself; rather, a generalized workflow is considered that can be applied to any fracture stimulation. The workflow is, therefore, independent of any specific stimulation application. For the sake of clarity, the approach described uses a single planar fracture in a vertical well.
Simon Chipperfield, SPE, age 50, died in a plane crash in the Philippines while working on a geothermal project on 18 February 2023. He was a recognized technical expert in the fields of diagnostic testing of hydraulically fractured wells, well performance in tight gas reservoirs, and reserves and forecasting for conventional and unconventional reservoirs. Chipperfield was the director of EnergyNow and served as an advisor for Energy Development Corporation, specializing in subsurface geothermal resources, subsurface well services, and drilling groups. He began his career in 1995 as a senior completions and drilling engineer for Santos Ltd. in Adelaide, South Australia. He later worked as a senior production technologist for Shell in Houston before returning to Santos Ltd. in 2005, where he would remain until 2021.
Lima, Gustavo Filemon Costa (Nuclear Technology Development Center and Centro Federal de Educação Tecnológica de Minas Gerais) | Lima, Jussara Da Silva Diniz (GASBRAS Project) | Duarte, Joyce Castro de Menezes (Nuclear Technology Development Center) | Ferreira, Vinícius Gonçalves (GASBRAS Project) | Filho, Carlos Alberto De Carvalho (Nuclear Technology Development Center) | Dufilho, Ana Cecília (Universidad Nacional del Comahue) | Moreira, Rubens Martins (Nuclear Technology Development Center) | Ciminelli, Renato Ribeiro (GASBRAS Project)
Abstract The definition of a predominant geogenic source of ions and its respective background ranges are powerful tools for detecting contaminations coming from the unconventional gas industry at earlier stages. Reference data to compare pre- vs post-drilling may enforce the planning, monitoring, and management in favor of unconventional production sustainability in the long-term. In 2022, the Brazilian Government launched a pilot project named "Transparent well" for public consultation, intending to foment its incipient unconventional hydrocarbon industry. In this context, this study presents preliminary results to compound an environmental baseline to structure reference data about water resources in a pre-drilling scenario. Then, a characterization of surface water and a geochemical background proposal of Indaiá and Borrachudo basins, two potential tight gas plays inside the São Francisco Basin, was performed to understand hydrochemical processes and susceptibilities previously the unconventional industry development. Two sampling campaigns collecting 13 samples each were made to characterize the study area in two different scenarios. Chemical analysis was performed using an Inductively Coupled Plasma - Mass Spectrometry. To settle a hydrochemical background and its respective environmental thresholds, the ±2 Median Absolute Deviation method was applied. Piper and Chadha's diagrams were used to define water-type and the major cations/anions dynamics in the environment. Piper diagram shows three distinct predominant water-type in the study area, Group 1 (Ca-Mg-HCO3-type); Group 2(Na-K-Ca-HCO3-type); and Group 3 (Ca-Na-HCO3-type). Groups 1 and 2 reflect a geological control in the hydrochemistry due to an interaction between the surface water and interlayered strata of Carbonates and Siltstones from the Bambuí Group whereas Group 3 suggest a seasonal influences in water chemistry. Background values and Upper/Lower environmental thresholds for nineteen elements in two different seasons were also proposed for the study area. Reference data to compare pre- vs post-drilling may enforce the planning, monitoring, and management in favor of unconventional production sustainability in the long-term. Environmental baselines focused on water resources may be a key to the responsible development of the incipient unconventional gas industry in Brazil.
Wang, Yang (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum Beijing, China) | Yao, Yuedong (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum Beijing, China) | Wu, Hao (CNOOC Research Institute Co., Ltd., Beijing, China) | Dai, Jinyou (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum Beijing, China) | Wang, Lian (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum Beijing, China) | Mu, Zhongqi (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum Beijing, China)
Abstract Low-production wells can often be found during the process of gas field production, particularly in low-permeability and tight gas reservoirs. In the Jingbian gas field, some wells (defined as abnormal-low-production wells (ALPWs)) have a much earlier decline period, a larger decline rate, and greater remaining dynamic reserves. In this paper, the low-production gas wells in the Xiagu gas reservoir of Jingbian gas field are taken as the research object, and the existing static and dynamic data of the gas field are comprehensively studied. To enhance the production of the ALPWs, this study focused on the production characteristics, decline causes, and applicable countermeasures of the ALPWs. Static and dynamic data from 57 low-production wells in the Xiagu gas reservoir were analyzed. In addition, differences in production characteristics between traditional low-production wells and the ALPWs are compared using production, pressure and other development indicators. Furthermore, the rapid identification and selection criterion of the ALPWs is established by implementing the producing indexes of the ALPWs. The study shows that several characteristics of the ALPWs can be determined by the production-pressure limiting method. The main determination criteria are listed as follows: The annual production decline rate is more than 20% (far greater than the normal annual decline rate of 5%). The single gas well continues to produce for more than 30 days with a daily production of 10000 m. The tubing-casing pressure differential is greater than 2.5MPa. The most significant characteristic is that the remaining dynamic reserves of the ALPWs are greater than 250 million m. All the above characteristics demonstrate that the ALPWs might still have great production potential and the causes for the abnormal-low-production could be analyzed by the node analysis and the IPR curve. Moreover, the bottom-hole water loading and wellbore plugging are the main causes of the abnormal-low-production. This research helps the engineers identify 57 ALPWs in Jingbian gas field, and puts forward adaptive countermeasures for the abnormal production decline causes, which helps the gas field achieve the goal of increasing production and stabilizing productivity. And it could be applied in other similar low-production gas wells with hydraulic fractures in tight gas reservoirs worldwide, and could provide research reference for the progress of enhancing productivity from the low-production gas wells.
Yu, Tianjun (Yanchang Petroleum Group) | Cao, Yongbo (Yanchang Petroleum Group) | Li, Ming (Schlumberger-CoPower) | Wang, Junfeng (Schlumberger-CoPower) | Zhang, Jie (SLB) | Liu, Yuan (SLB) | Luo, Yin (SLB) | Yang, Haihua (SLB) | Wang, Taiji (SLB) | Fendt, Andrew (SLB) | Liu, Peiwu (SLB)
Abstract Water-sensitive tight gas formations pose a unique challenge for fracturing treatments. A large fracture geometry and reservoir contact are often required in such tight formations, yet the injection of a high-volume treatment fluid may result in high risk of water sensitivity or even water-block issues. Significant reduction of treatment water and improvement of proppant placement are considered as the keys to resolving this dilemma. In our study, both nitrogen-based and carbon dioxide-based options were put into the field trials. With the engineering and operation parameters pushed to the extreme, it was found that high-quality foam fracturing with nitrogen was the most cost-effective treatment method. The S1 and H8 tight gas formations from the East Ordos basin, China, show much lower production potential compared to their neighboring blocks in the central basin. Normal fracturing practices, including gel-based fracturing, hybrid fracturing, and high-rate slickwater fracturing, were tested in those formations, and the results were not satisfactory. We discovered the root cause for the underperformance of the reservoir using evidence from lithology, magnetic resonance, and core analysis, which indicated that despite their mediocre porosity, those formations were often associated with high clay content and poor pore structures. Therefore, the effective permeability in those formations is not only lower than that of clean sandstones but is also easier to become impaired by the invasion of water. In such cases, stimulation with minimum water invasion is the key to unlocking the reservoir potential. Two different approaches were put on trial in our study; one was based on the supercritical carbon dioxide fracturing method, and the other was based on the high-quality nitrogen foam fracturing method. The carbon dioxide option was put on trial in early phases, and its success confirmed that such formation did have potential for production. However, this option is also accompanied by the operational challenges and excessive costs, which made the nitrogen-based solution more favorable. When the engineering and operation parameters were pushed to the extreme (i.e., the pressure was reaching the limits and the average proppant concentration rose to an unprecedented level), the outcome was satisfactory. Considering the treatment safety, water reduction ratio, proppant placement volume, cost reduction, and the positive production results, the aggressive nitrogen-based fracturing option was confirmed to be the better option for water-sensitive tight gas formation from East Ordos Basin. This paper addresses the dilemma of large-volume fracturing in water-sensitive tight gas reservoirs. Two foam options, nitrogen and carbon dioxide, were tested in the field with parameters pushed to the extreme. Although positive production results were observed from both options, operational safety and field economics were more favorable with the high-quality nitrogen option.
Abstract Forecasting the estimated ultimate recovery (EUR) for extremely tight gas sites with long-term transient behaviors is not an easy task. Because older, more established methods used to predict wells with these characteristics have shown important limitations, researchers have relied on new techniques, like long short-term memory (LSTM) deep learning methods. This study assesses the performance of LSTM estimations, compared to that of a physics-based reservoir simulation process. With the goal of obtaining reliable EUR forecasts, unconventional tight gas reservoir data is generated via simulation and analyzed with LSTM deep learning techniques, tailored for sequential data. Simultaneously, a reservoir simulation model that is based on the same data is generated for comparison purposes. The LSTM forecasting model has the added benefit of considering operational interventions in the well, so that the machine learning (ML) framework is not disrupted by interferences that do not reflect the actual physics of the production mechanism on well behavior. The comparison of the data-driven LSTM deep learning model and the physics-based reservoir simulation model estimations was performed using the latter framework as a benchmark. Findings show that the AI-assisted LSTM model provides predictions similarly accurate to the ones estimated by the physics-based reservoir model, but with the added capability for long-term forecasting. These data-driven EUR models show great promise when analyzing unusually tight gas reservoirs that feature time series well information, which can improve estimations about recovery and point engineers towards better decisions regarding the future of reservoirs. Therefore, exploring deep learning methods featuring varying types of artificial neural networks in greater detail has the potential to significantly benefit the oil and gas sector. When compared to other machine learning methods, novel deep learning techniques have advantages that remain underexplored in the literature. This paper helps fill this gap by providing a valuable comparison between older prediction methods and new estimation simulations based on neural networks that can predict long-term behaviors.
Abstract Horizontal drilling and completion advances in tight gas and shales have allowed access to significant new resources both in existing fields and new plays. Open hole multi-stage fracturing (MSF) technologies using ball operated sleeves and openhole packers have generally been effective in delivering high productivity wells, worldwide. Successful case histories treating tight shale gas with MSF completions abound in current literature, however, it is important to note that a majority of these case histories deal with reservoirs with high pressures. Often tight gas reservoirs are initially found to be over-pressured (higher than water gradient), but as with all depletion drive systems, the reservoir pressure depletes with the removal of fluids. Pressure depletion brings along with it its own set of challenges. The wells cease to have the ability to flow naturally to surface, liquid loading, and artificial lift are issues that come to the forefront. Conventional multi-stage stimulation that was seemingly fast and efficient in high pressure environment loses its appeal in sub-hydrostatic pressure wells. The time spent between each stimulation stage to the onset of well flowback becomes long and detrimental to the recovery of the well. The fracturing fluid lost to the formation can negatively alter the relative permeability of gas in the reservoir and the longer the time spent to recover the fluids the damage tends to get irreversible. Quick and efficient clean-up of fracturing fluid is indispensable to maintain a well's productivity in tight, low pressure gas reservoirs. A new generation of multi-stage completion systems is discussed in this paper. These multiple stage tools are operated by a single ball that opens several of the treating sleeves in one run thus allowing a large section of the reservoir to be treated simultaneously. The stimulation fluid placement is enhanced by pumping through limited entry ports of the stimulation sleeves at optimum injection rates supported by modern particulate diverting agents, and energized fluids. The operation time between the first stimulation (acid) stage hitting the formation to the well being flowed back can be cut down to a matter of few hours from an otherwise operation of a few days. The results from this step change in completion and stimulation design have been spectacular providing several folds of productivity improvement. This application provides a fundamentally sound solution for treating low pressure, tight reservoirs.
Abstract Fracturing in tight and deep gas formations can be challenging when near-wellbore stresses reduce injectivity. The drilling fluid may contribute to a near-wellbore damage, and this will exaggerate the rock breakdown limits additional to the high local stresses. The paper will present case history review of different techniques in addressing low injectivity in tight gas wells to minimize delays in operations and associated risks. Different stimulation techniques are utilized to enhance the production from tight gas carbonates reservoirs, including multistage fracturing completions and techniques as plug and perf, sliding sleeve systems, coiled tubing conveyed stimulation systems, etc. regardless of completion method type, the damage level could still be present, in addition to the stress cage around the wellbore, hence the injectivity can be very challenging. There are frequent cases, when during the injection stage the pumping rate barely reaches 1 bpm at maximum allowed pressures. And there are several solutions, such as acid squeeze treatment conveyed by coiled tubing, abrasive jet perforations, bullhead acid spearhead stage at lowest pumping rate, completion fluid solvents and others. Each method has different criteria for applicability, depending on the technical scenarios and require critical decision-making process during the operational performance. Due to damage presence in the near-wellbore zone, the injection rate was observed to be below 1 bpm and surface pressure could be reaching the completion limitations, and the possibility of job cancellation becomes high. Therefore, proper solutions were required to improve the injection prior to fracturing treatment. The case study showcases some statistical analyses of solving the challenges concerning the near-wellbore damage and improving the injectivity prior to main stimulation treatment. The case studies review will help optimizing the technical decision when injectivity challenges occur in tight gas reservoirs and could be used as a reference in other HPHT fracturing projects.