Comprehensive Analysis of Production Loggings in Fuling Shale Gas Play in China

Fuling shale gas field is one of the most successful shale gas play in China. Production logging is one of the vital technologies to evaluate the shale gas contribution in different stages and different clusters. Production logging has been conducted in over 40 wells and most of the operations are successful and good results have been observed. Some previous studies have unveiled one or several wells production logging results in Fuling shale gas play. But production logging results show huge difference between different wells. In order to get better understanding of the results, a comprehensive overview is carried out. The effect of lithology layers, TOC (total organic content), porosity, brittle mineral content, well trajectory is analyzed. Results show that the production logging result is consistent with the geology understanding, and fractures in the favorable layers make more gas contribution. Rate contribution shows positive correlation with TOC, the higher the TOC, the greater the rate contribution per stage. For wells with higher TOC, the rate contribution difference per stage is relatively smaller, but for wells with lower TOC, it shows huge rate contribution variation, fracture stages with TOC lower than 2% contribute very little, and there exist one or several dominant fractures which contributes most gas rate. Porosity and brittle minerals also show positive effect on rate contribution. The gas rate contribution per fracture stage increases with the increase of porosity and brittle minerals. The gas contribution of the front half lateral and that of latter half lateral are relatively close for the "upward" or horizontal wells. However, for the "downward" wells, the latter half lateral contribute much more gas than the front half lateral. It is believed that the liquid loading in the toe parts reduced the gas contribution in the front half lateral. The overview research is important to get a compressive understanding of production logging and different fractures’ contribution in shale gas production. It is also useful to guide the design of horizontal laterals and fractures scenarios design.

A New Model for Predicting Liquid Loading in Shale Gas Horizontal Wells

Current critical flow rate models fail to accurately predict the liquid loading statuses of shale gas horizontal wells. Therefore, a new critical flow rate model for the whole wellbore of shale gas horizontal wells is established. The results of the new model are compared to those of current models through the field case analysis. The new model is based on the dynamic analysis and energy analysis of the deformed liquid-droplet, which takes into account the liquid flow rate, the liquid-droplet deformation and the energy loss caused by the change of buildup rate. The major axis of the maximum stable deformed liquid-droplet is determined based on the energy balance relation. Meanwhile, the suitable drag coefficient equation and surface tension equation applied to shale gas horizontal wells are chosen. Finally, the critical flow rate equation is established and the maximum critical flow rate of the whole wellbore is chosen as the criterion for liquid loading prediction. The precision of liquid loading prediction of the new model is compared to those of the four current models, including Belfroid's model, modified Li's model, liquid film model and modified Wang's model. Field parameters of 29 shale gas horizontal wells are used for the comparison, including parameters of 18 unloaded wells, 2 near loaded-up wells and 9 loaded-up wells. Field case analysis shows that the total precision of liquid loading prediction of the new model is 93.1%, which is higher compared to those of the current four models. The new model can accurately predict the liquid loading statuses of loaded-up wells and near loaded-up wells, while the prediction precision for unloaded wells is high enough for the field application, which is 88.9%. The new model can be used to effectively estimate the field liquid loading statuses of shale gas horizontal wells and choose drainage gas recovery technologies, which considers both the complex wellbore structure and the variation of flowback liquid flow rate in shale gas horizontal wells. The results of the new model fill the gap in existing studies and have a guiding significance for liquid loading prediction in shale gas horizontal wells.

Prediction of critical liquid loading time for water-producing gas wells: Effect of liquid drop rotation

After more than 20 years of continuous development, part of the wells in the Moxilei-1 gas reservoir located at the Sichuan Basin have entered the middle–later production stage. With the continuous decline in formation pressure and production rates, some of the gas wells have entered the potential period of liquid loading, while some have already suffered water plugging. Currently, the field engineers usually carry out some corresponding drainage measures after the occurrence of liquid loading in the gas well, which will first affect the production progress of the gas field, then increase the difficulty in drainage and reduce the drainage effect afterward. On the basis of Pan’s model for evaluating critical liquid-carrying flow rate, the influence of liquid drop rotation was considered in the new model. Further, combined with the Arps production decline equation, a prediction model of liquid loading timing was deduced. Taking a typical well in the Moxilei-1 gas reservoir as an example, based on the early-stage production data of the gas well, the model was used to predict the liquid loading timing accurately. The model can predict the possibility and timing of liquid loading in gas wells at different production stages. It can check the gas wells with potential liquid loading, so as to reduce the workload for field workers. Furthermore, it can predict the potential liquid accumulation and its timing in advance, so as to guide the field workers to prepare for drainage in advance.

Optimizing Tubing and Liner Completion Design to Improve Gas Production from Existing Wells: Case Study for ADNOC Onshore Field Abu Dhabi, UAE

An onshore gas field contains several gas wells which have low–intermittent production rates. The poor production has been attributed to liquid loading issue in the wellbore. This study will investigate the impact of optimizing the tubing and liner completion design to improve the gas production rates from the wells. Numerous sensitivity runs are carried out with varying tubing and liner dimensions, to identity optimal downhole completions design. The study begins by identifying weak wells having severe gas production problems. Once the weak wells have been identified, wellbore schematics for those wells are studied. Simulation runs are performed with the current downhole completion design and this will be used as the base case. Several completion designs are considered to minimize the effect of liquid loading in the wells; these include reducing the tubing diameter but keeping the existing liner diameter the same, keeping the original tubing diameter the same but only reducing the liner diameter, extending the tubing to the Total Depth (TD) while keeping the original tubing diameter, and extending a reduced diameter tubing string to the TD. The primary cause of the liquid loading seems to be the reduced velocity of the incoming gas from the reservoir as it flows through the wellbore. A simulation study was performed using the various completion designs to optimize the well completion and achieve higher gas velocities in the weak wells. The results of the study showed significant improvement in gas production rates when the tubing diameter and liner diameter were reduced, providing further evidence that increased velocity of the incoming fluids due to restricted flow led to less liquid loading. The paper demonstrates the impact of downhole completion design on the productivity of the gas wells. The study shows that revisiting the existing completion designs and optimizing them using commercial simulators can lead to significant improvement in well production rates. It is also noted that restricting the flow near the sand face increases the velocity of the incoming fluid and reduces liquid loading in the wells.

Mature Field Revitalization: Extending Late Life of Mature Gas Condensate Wells by Modelling Complex Multilateral Wellbore Flow Dynamics and Validating Results With a Field Pilot

Sharjah National Oil Corporation (SNOC) operates 4 onshore fields the largest of which has been in production since the 1980's. The majority of wells in the biggest field have a complex network of multilaterals drilled using an underbalanced coiled tubing technique for production enhancement in early 2000s. The scope of this project was to maximize the productivity from these wells in the late life by modelling the dynamic flow behaviour in a simulator and putting that theory to the test by recompleting the wells. A comprehensive multilateral wellbore flow study was undertaken using dynamic multiphase flow simulator to predict the expected improvement in well deliverability of these mature wells, each having 4-6 laterals (Saradva et al. 2019). The well laterals have openhole fishbone completions with one parent lateral having subsequent numerous sub-laterals reaching further into the reservoir with each lateral between 500-2000ft drilled to maximize the intersection with fractures. Complexity in simulation further increased due to complex geology, compositional simulation, condensate banking and liquid loading with the reservoir pressure less than 10% of original. The theory that increasing wellbore diameter by removing the tubing reduces frictional pressure loss was put to test on 2 pilot wells in the 2020-21 workover campaign. The results obtained from the simulator and the actual production increment in the well aligned within 10% accuracy. A production gain of 20-30% was observed on both the wells and results are part of a dynamic simulation predicting well performance over their remaining life. Given the uncertainties in the current PVT, lateral contribution and the fluid production ratios, a broad range sensitivity was performed to ensure a wide range of applicability of the study. This instils confidence in the multiphase transient simulator for subsurface modelling and the workflow will now be used to expand the applicability to other well candidates on a field level. This will result in the opportunity to maximize the production and net revenues from these gas wells by reducing the impact of liquid loading. This paper discusses the detailed comparison of the actual well behaviour with the simulation outcomes which are counterproductive to the conventional gas well development theory of utilizing velocity strings to reduce liquid loading. Two key outcomes from the project are observed, the first is that liquid loading in multilaterals is successfully modelled in a dynamic multiphase transient simulator instead of a typical nodal analysis package, all validated from a field pilot. The second is the alternative to the conventional theory of using smaller tubing sizes to alleviate gas wells liquid loading, that high velocity achieved through wellhead compression would allow higher productivity than a velocity string in low pressure late life gas condensate wells.

Automated Intelligent Alarms to Monitoring and Identify Liquid Loading Challenge for Giant Depletion Gas Condensate Fields

Depleted well monitoring is a crucial task to ensure continuous production without facing substantial issues that withhold the production, such as liquid loading. Utilizing an integrated digital production system and custom intelligence alarms functionality can help identify and analyze this bottleneck using physics-based model estimations that can help users take preventive actions, leading to saving cost, time, and effort. This paper demonstrates the identification of the liquid loading using custom intelligence alarms and an automated framework. Initially, a representative compositional well model is added to the digital twin solution enabling the automated well analysis workflow. Subsequently, custom intelligence alarms guidelines are configured to keep the well's performance and production rates under supervision with a notification capability when parameters violate the guidelines. Along with various well performance parameters being analyzed, two critical parameters for liquid loading debottlenecking, critical unloading velocity and the In-situ velocity, are investigated in the system for each well as the function of depth along well's completion. Moreover, advanced dashboards report the analysis output in an informative manner, guide users’ engineering judgment to take preventive decisions. As a result of the custom intelligence alarm, gas condensate wells suffering from liquid loading were predicted and identified. Based on the production parameter and target monitoring, these wells were unable to produce their expected mandate resulting in violating the set of production parameters guidelines. Identified wells were run through production gas rate sensitivity analysis using the analytical tool, and in conclusion, the optimal production rate was calculated. Producing the well below this critical rate causes the In-situ velocity to drop below critical unloading velocity. Additionally, using the tuned and calibrated network model, the operating choke was identified to maintain the stable flow in the well and avoid further liquid loading. This choke size was provided to field operation for implementation and saved the cost and man-hour spent during the flowing gradient surveys. The case study demonstrates significant production improvements observed for these wells, thereby significantly reducing cost and time. Using the integration of the latest production optimization platforms and custom intelligence alarm provides tools to identify wells that are currently experiencing liquid loading challenges and healthy wells that might come under the liquid loading category in the course of production, thus helping in taking proactive remedial action. Furthermore, the integrated framework provides erosional velocity-related data, which acts as a guideline while optimizing gas production.

Successful Improvement of Ultimate Recovery of Complex Deep Tight Gas Field via Combined Gas Lift De-Liquification Techniques

The Amin top structure is Well defined in seismic data and can be easily interpreted across the entire area of North Oman. It is being identified as an extremely tight, disconnected, low porosity, low permeability, and HPHT reservoir, and thus presents unique challenges to harness its full production potential. Approximately, 15 years after production began with significant pressure depletion below dew point, a significant loss in Well productivity occurred in some of the Wells. Furthermore, during shutdowns or sudden trips of production stations, more Wells faced difficulties to restart again due to mainly, condensate banking and other probable reasons like formation water cross-flow during shut-in, which created a water bank and impaired inflow performance liquid loading due to low Well bore pressure which caused higher static head at the Well tubing. Common practice of N2 lifting CTU becoming no economical with increase number of Wells suffer from Liquid loading and represented a major challenge to look for cheaper economic alternatives. To reduce the higher OPEX associated with nitrogen lifting of Wells, multiple options were considered and evaluated thoroughly including extensive study of several artificial lift methods which were thought to defer liquid loading and mitigate kick-off issues such as Foam lift, Plunger lift, Beam Pump, ESP, Jet Pump and Gas lift (Concentric gas lift). The optimum gas Well de-liquification method has been identified based on the highest UR considering connected GIIP and inflow resistance A (Forchheimer equation Laminar flow). The outcome of the study indicated that a gas lift technology combined with well retubing was recommended as the optimum solution. The injected gas has reduced the density of the liquid resulting in reducing the static head at the tubing which increased the Well bore pressure allowing the Well to flow. A successful robust pilot which has been completed in two Wells and gave conclusive results. The surface development concept encompasses the development, with long term testing. The outstanding successful outcomes of the pilot succeeding in restoring Wells back with economic prolific production rates have led to expedite a full field implementation plan in three fields covering (33 Wells) in the next 5 years. These Wells have similar sub-surface and surface conditions. This paper will highlight the full story of the Gas lift technology implementation and describe in details the entire process starting from the Well candidate selection screening criteria, concept detailed design, critical success factors, project assurances and controls, Injection rate and operating parameters, facility capex, life time cycle and the result tested gas & condensate and water production. Also, the learning and challenges like halite accumulation effects will be shared along with the proven practical mitigation plan that ensured and sustained Well production resulting to significant project success of the technology.

The Implementation of Critical Gas Rate in Liquid Loading Well and Optimization Analysis using the Adequacy Chart

In the gas well, liquid loading occurs when the gas rate is insufficient to lift liquids into the surface such as water and/or condensate. This causes an accumulation of the liquid in the wellbore, supplies additional backpressure to the formation, and may completely kill the well. Meanwhile, the limited space and typically high cost of offshore operations have made a proper study for optimization selection very essential. The selected project must fulfill several requirements, namely: 1) Fit for the purpose, 2) Low risk and uncertainties, and 3) Economic. Hence, this study will describe the pilot project and continuous improvement process of lowering the gas well pressure using a wellhead compressor and a temporary separator to optimize the liquid loading. It also explains the implementation of critical gas rate in predicting the liquid loading event from the well’s production history. A new analysis method utilizing the adequacy chart was proposed to verify the suitability of the available pressure-lowering system unit available in the market with the well candidates. An adequacy chart was constructed from the well’s deliverability, critical gas rate, and lowering pressure unit or system capacity. These three charts will combine to generate an overlapping area, which signifies suitability for the recommended operation. The well’s production data history can be used to predict the liquid loaded-up event due to the continued decline of the generated gas. Also, a combination of the critical gas rate and decline analyses can predict potential liquid loading problems.