bluuebunny/crossref_metadata_2025 huggingface dataset:
Managing Gas-Constrained Facility: Converting Oil Producer into Gas Injection Well
Authors: Kurniawan M. F. , Desmono L.
Published: October 2024

In accordance with Banyu Urip reservoir simulation for production outlook, produced gas is increasing over time causing the facility to become gas-constrained. With approximately 80% of the gas is being re-injected back for reservoir pressure maintenance, the existing Gas Injection (GI) capacity is limited by the backpressure which is close to the compressor pressure limit. Well conversion helps to resolve these challenges, subsequently allowing more gas production which translates to higher oil production.

Repurposing the existing shut-in oil producers into gas injection wells require surface piping modification. The development of this project needs Surface and Subsurface team collaboration to acquire both hydraulic benefit and meet reservoir pressure maintenance requirement. It mainly consists of:

Well selection criteria for shut-in oil producers Surface piping system modification concept and hydraulic calculation Gas injection wells operation and injectivity performance observation Address challenges from the converted wells (sulfur deposition, schmoo formation, injectivity loss)

Subsurface selection criteria for conversion well candidate include ensuring all perforation intervals are already within gas zone by performing contact logging to evaluate the latest gas-oil contact.

Selecting the appropriate gas supply route proved to be beneficial for gas injection wells operation and performance, as well as for the oil production. Injectivity data suggests that supplying gas injection from the gas lift manifold resulted in lower backpressure by 900 kPag, compared to flowing gas from gas injection manifold. Furthermore, two additional Gas Injection (GI) wells resulted in the significant reduction of compressor discharge pressure, allowing more gas to be re-injected back to the reservoir. It also provides more flexibility to perform one GI well preventive maintenance without continuous flaring.

The project has successfully increased the gas injection capacity by approximately 30%, thus allowing higher produced gas to be handled by the system. It translates to additional oil production of 4,000 – 6,000 bbls/day while maintaining lower emission.

This paper provides insight of successful effort in converting oil producer wells into gas injection wells with a proper measure and precautions for a gas-constrained facility. Simple modification of well conversion proved to be giving higher injection capacity and significantly impact the oil production.
New Production Technology Implementation, as an Effort to Achieve 1 Million Barrels Oil for National Production Per Day in 2030
Authors: Falach Achmad Rocky , Ihsan Alfandra , Kauripan Satria Panji , Warasta Ageng , Dewi Amalia Kusuma
Published: October 2024

Arresting decline and maintaining high existing production is one of the main strategy to achieve Indonesia's main goal oil production one million barrels oil per day in 2030. Most of existing fields in Indonesia are mature fields, where there are no more "easy oil" to boost up production with conventional methods. In other words, we need more advanced technology to seek the possibility to increase production. This paper will describe the effort of implementing new production technology since 2020 until 2023 and how its impact on the national oil production. It is hoped that an overview of the effectiveness of new production technology implementation will be obtained as well as possible improvements or massive implementation that can be made in the future.

This evaluation process was done by analysing new production technology implementation since 2020 until 2023, consist of type of the technology, its direct impact on national oil production, possible contract scheme to open the opportunity and also challenges that we were facing during the implementation process.

Monitoring the implementation started in 2020, where there were eight technologies that successfully implemented which gave production gain around 451 BOPD. On the following year, six technology implemented gave 557 BOPD additional gain. A higher production gain, around 1,778 BOPD, was achieved in 2022 from fifteen technology implementation. And, last in 2023, there were seven technology giving another success in production with gain around 532 BOPD.

From 2020 to 2023, technology implementation successfully gave positive impact to national oil production, especially on existing wells. Technology implemented consists of sand control technology, artificial lift and stimulation. The more technology applied, the more the results would be. But, factors like subsurface condition, integrity of the wells, contracts, and economics appeared to be the key parameters that determine the success of the technology applied.

Implementing new technology is one of the potential solution to increase production and seek to open new potential for field or wells that could not produce using conventional method. But to make it into a bigger scale and massive implementation would need a solid collaboration between services company, oil company, government, academic institution and other stakeholders also a win-win contract scheme.
Applied Modelling of Shale Oil Cross-Scale Flow Behaviors in Gulong, China
Authors: Lei Zhengdong , Ge Chenqi , Ji Dongqi , Peng Yingfeng , Zhang Guangming , Chen Zhewei , Liu Yishan
Published: October 2024

Gulong shale oil is characterized by abundantly enriched nanopores and bedding fractures. A critical challenge of shale oil reservoir simulation is the representation of complex cross-scale flows among tight matrix, bedding fractures and hydraulic fractures, which require fine gridding and massive computation. A simulation approach of shale oil flow by combining multiple-interacting-continua (MINC) and discrete-fracture-network (DFN) is provided to investigate the flow behaviors of shale oil. Dynamic bedding fractures dilation under varying reservoir stresses is predicted by the Barton-Bandis model. Compared to the conventional methods of Gulong shale oil simulation by simple grid system, the resultant coupled MINC and DFN model with dynamic bedding fractures consists of an approach at constructing a rigorous relation between the flow nature of the macroscopic hydraulic fractures and the shale microstructures mainly characterized by the presence of shale matrix and bedding fractures. Cross-scale flow behaviors are investigated and numerical simulations are performed to efficiently predict production performance in Gulong shale oil reservoir. Relevant analysis based on simulation results suggest further considerations on the efficient modelling of cross-scale flows in shale oil reservoirs.
Application of Integrated Production System Modelling (IPSM) for Long-Term Production Forecasting and Optimization, a Case Study in Deepwater Assets, Malaysia
Authors: Surin N. , Kok K. C. , Hutamin N. , Rofieq S. K. , MousaviMirkalaei S. M. , Syah G. , Edmondson M.
Published: October 2024

In typical integrated simulation projects involving multiple reservoirs connected to a single producing facility, poor communication between production and reservoir engineers, who use different analysis tools, often leads to unreliable results. CoFlow is an integrated production system modelling (IPSM) tool and platform that helps RE's and PE's overcome these challenges. This work studies how CoFlow was used to provide robust, long-term (10 years plus) production forecasting and optimization for a deepwater oil development in Malaysia.

Currently ongoing deepwater projects off the coast of Sabah are critical to sustaining Malaysia's crude oil output. These projects face high costs due to specialized equipment and subsea infrastructure installation, making it a necessity to simulate the complete fluid journey from the subsurface all the way to the oil platforms to ensure engineering design and consistency during forecasting. One such project, henceforth named Field G, has been built as an IPSM model in CoFlow. An IPSM model includes the reservoir model(s), the wellbore models as well as the piping and equipment that form the asset's surface network.

Field G IPSM model was used to couple two reservoirs and link them to a complex surface network system, whereby the produced gas was separated and re-injected into the reservoirs using a custom algorithm. The IPSM model was operated using network-level constraints, which mimic the maximum fluid handling capacities of certain equipment on the production platforms. This is a unique and often overlooked capability of IPSM models, and it helps to make sure that the system is not producing beyond the limitations imposed by its surface network. The model was run for simulation times greater than 16 years, enabling forecasts that reach critical junctures in the field life such as the end of a PSC. Furthermore, maximum gas and liquid rate constraints were imposed on the models and various well operating scenarios were assessed to find the most optimum solution. All this could not be captured with just regular reservoir simulation, hence showcasing the value and importance of IPSM for large offshore projects.

This was the first time that the G field was collaboratively modelled using IPSM approach and used to simulate forecast periods longer than 10 years. The CoFlow platform provided fast runtimes which allowed the authors to run multiple prediction scenarios and saved many man hours. Moreover, the IPSM model helped capture the complex interactions between facilities and reservoir performance through integration and multi-disciplinary collaboration.
Plunger Lift System: A Field Implementation Case Study in Upper Assam Shelf Basin
Authors: Maut Partha Protim , Prakash Yerra , Dutta Udai Anand , Saikia Partha Protim , Sowmyanarayanan N M , Yadav Abhishek
Published: October 2024

Plunger lift is an economical artificial lift system applicable to high gas-liquid ratio gas wells and gas lift wells. This rig-less hybrid technology was deployed in various marginal fields of the Upper Assam Shelf Basin with the primary objective of extending the economic lifespan of the wells. The project involves candidate selection, installation, commissioning, optimization, and troubleshooting of plunger Lift system in gas wells and intermittent gas lift wells.

In this project, plunger lift system is installed in gas wells with the following objectives:

Potential increase in overall influx due to deliquification. Reduced liquid fall back, which results in overall crude oil gain. Increased gas production. The tubing bore is kept clean by eliminating hydrate and scale deposits.

The intermittent gas lift wells are operated with conventional gas lift mandrels and valves. The plunger lift system was integrated with the gas lift system to eliminate common gas lift well inefficiencies to achieve the following:

Minimize liquid slippage and fallback control. Decrease issues related to paraffin deposits. Increase oil production.

This paper presents an exceptionally detailed analysis of the plunger lift system installed in gas and intermittent gas lift wells, which provides a mechanical interface between gas and liquid for:

Improved drawdown and maximized flow potential. Cyclic deliquification of gas wells. Stabilized gas and liquid flow. Increased overall efficiency of the gas lift system. Resumption of a normal decline curve. Enhance the economic lifespan of the well. Delays high CAPEX expense of other artificial lift system methods.

The paper emphasizes the selection of potential wells, integrating plunger lift systems for gas and intermittent gas lift wells, optimizing the gas lift system, and troubleshooting. This hybrid project was successfully executed to increase oil, condensate, and gas production in addition to reducing paraffin deposit-related issues, compression horsepower, and overall operating expenditure while maintaining an optimized injection gas rate. A detailed analysis of the plunger lift system optimization and troubleshooting has been presented in this paper. This plunger lift project resulted in an overall average of 36% liquid and 83% gas gains in the candidate wells of the Upper Assam Shelf Basin.

A significant potential for low investment and rapidly increasing production and development of the reserve lies in the application of plunger lift systems in gas and intermittent gas lift wells. As a result of this project, we have gathered valuable technical experience that shows plungers can substantially increase production in gas and intermittent gas lift wells in brownfields in the Upper Assam Shelf Basin and other exploration and production (E&P) companies throughout the world.
Development of a Novel Modelling Tool for Condensate Emulsions: Key Factors Influencing Oil-In-Water Emulsions
Authors: Amir M. Mahamad , Halim N. , Sagar S. Wan , Razali N. , Shafian S. M , Zulkifli N. , Razak A. A , Hendraningrat L. , Baharuddin S. , Zainal S. , Othman A. Ahmad , Wahab M. A , Noor M. Md , Sedaralit M. , Yusof M.
Published: October 2024

As the global energy landscape shifts towards cleaner alternatives like natural gas, managing the emulsions in condensate production becomes increasingly important for environmental compliance and operational efficiency. This study presents the development of a novel modelling tool designed to predict condensate emulsions, focusing on key factors causing emulsions such as pH, solid content, asphaltene concentration, droplet size, and organic acids. Through a series of controlled experiments using turbidity measurements, transmission analysis, and the Turbiscan Stability Index (TSI), the effects of these variables on emulsion stability were systematically evaluated. The findings reveal that higher shear rates and presence of asphaltenes significantly enhance the emulsion stability, while pH and organic acid content play complex roles in either stabilizing or destabilizing the emulsions. The modelling tool offers a predictive capability for emulsion behavior, aiding in the optimization of separation processes and improving effluent discharge quality (EDQ) to meet stringent environmental standards. This research contributes to better emulsion management strategies in the oil and gas industry, particularly in fields with condensate production ensuring both improved operational outcomes and environmental protection.
Research on Key Materials and Systems of Ultra High Temperature Cement Slurry for Ultra-Deep Wells Cementing
Authors: Xiujian XIA , Yongjin YU , Fengzhong QI , Huiting LIU , Congfeng QU
Published: October 2024

With the continuous deepening of oil and gas exploration and development, the number of ultra-deep and ultra-high temperature wells is gradually increasing in China. The key materials and systems of cementing slurry are crucial for ensuring the safe construction of wells, effective sealing of cement sheath, and safe production of oil and gas. However, the complex working conditions such as ultra-high temperature pose serious challenges to the materials and systems of cement slurry. Focusing on the technical difficulties of ultra-high temperature cement slurry for deep and ultra-deep wells cementing, the cementing retarder, fluid loss additive, stabilizer, and set cement strength retrogression inhibitor with the temperature resistance of 240 ° C were developed through the technical methods, such as optimizing polymer molecular structure, surface modification of powder materials, and synergistic effects between materials. The novel cement slurry system with the temperature resistance of 240 ° C was formed on basis of the above-mentioned four key additives and their supporting materials. Its comprehensive performance was evaluated. The cement slurry system has the resistance to bottom hole circulating temperature of 240 ° C. After curing at 240 ° C, the settling stability of cement slurry can be controlled within 0.05 g/cm3, the API fluid loss is less than 50 mL, and its thickening time can be adjusted arbitrarily within 200 to 600 min, which is linearly related to the test temperature and retarder dosage. The compressive strength of set cement is 45.8 MPa and 55.2 MPa cured at 240 ° C for 2 d and 28 d, respectively. The comprehensive performance of the cement slurry system is excellent, solving a series of problems such as slurry instability, non-adjustable thickening time, uncontrollable water loss, cement stone cracking, and strength decline under ultra-high temperatures. It can meet the requirements of the ultra-high temperature cementing operations and long-term sealing of cement sheath for complex deep and ultra-deep wells. The key materials and systems of ultra-high temperature cement slurry have been successfully applied for more than 20 wells in China, including the highest temperature well of Qiantan 1 with 213 ° C in Dagang Oilfield and the deepest vertical well Pengshen 6 in Asia with 9026 m. The novelty of this paper is in the ability to solve the problems of high-temperature performance failure of cementing additives and the instability of slurry system. Meanwhile, it can provide the technical guidance for the polymer structural design and synthesis of key additives, and the formation of ultra-high temperature cement slurry. It plays an important role in the safe and efficient exploration and development of deep and ultra-deep oil and gas.
Analyzing Greenhouse Gas Emission Leading Indicators: Case Study of Compressor Profile Optimization
Authors: Kongkiatpaiboon Suradech , Apornsupavit Asit , Manoharn Songkiet , Phetket Chawanin , Nimanong Sasiwan , Prabhasawasdi Saranya , Charungrattanapong Worasak
Published: October 2024

This study examines energy efficiency and emission management projects as well as the challenges and solutions. Best practices are identified through multiple workshops, and they are applied to our emission data. These include reviewing factors impacting energy performance, and benchmarking visualization across locations and comparing key equipment. Upon extensive analysis, it becomes evident that there is a significant decrease in the operating pressure of the sales gas export pipeline in comparison to its previous state. Consequently, the optimization of compression profiles is necessary to effectively reduce emissions.

Standard emission dashboards primarily report lagging indicators, such as the quantity of emitted gas and burned fuel gas. These factors are significant, but they are measured after the fact. Another important parameter to be considered is the leading indicator. However, the analysis and focus on equipment activities or instrument operations that contribute to lagging indicators are typically lacking.

The compression system in gas processing plants is widely recognized for its high fuel consumption. This is mainly influenced by three factors: compression ratio, engine speed, and critical valve operation, which are responsible for maintaining the pressure profile. Opportunities exist for our plants due to the significantly lower sales gas pipeline pressure compared to the original design conditions. This is coupled with the fact that the compression ratio remains the same. After thorough engineering analysis, we have identified that the opening of recycle valves, anti-surge valves, and back pressure control valves are the primary indicators that are valuable for visualizing and implementing decisive measures. Engineering measures have been implemented to address the limitations, allowing the compressors to operate at lower speeds. This has led to a significant reduction in emissions and operating expenses.

The increasing convenience of the world poses a significant environmental concern for future generations. Mitigating it effectively is challenging. This study examines various efforts and proposes an effective approach for monitoring, visualizing, and managing emissions in gas processing plants’ compression system. This paper will benefit individuals engaged in emissions reduction efforts and anyone interested in contributing to environmental preservation.
Analysis of Ammonia Discharged from Ammonia Fuel Supply System During Ammonia Depressurization Process According to Recovery Pressure
Authors: Jeong G. , Go W. , Jung J. , Park J. , Seo Y.
Published: October 2024

The dual-fuel engines secure the stability of the engine and the fuel supply system through a purging process with nitrogen in situations such as dual-fuel stop or shutdown. However, since ammonia has fatal toxicity depending on its concentration and exposure time, discharged flow analysis of the ammonia fuel supply system is required. In this study, the flow characteristics of ammonia and nitrogen mixture discharged from the fuel supply system were analyzed by simulating the ammonia purging process with Aspen HYSYS. The fuel supply system was modeled for the ammonia engine under development from MAN ES, and some parts of fuel supply system were estimated. Purged ammonia was mixed with water in the ammonia catch system except for the amount that can be recovered. The investigation reveals that as the recovery pressure increases, the amount of recovered ammonia also increases. Simultaneously, the amount of ammonia discharged into the atmosphere through the water tank decreases. The results showcase a positive correlation between recovery pressure and the efficiency of ammonia recovery during the depressurization process. These findings contribute valuable insights for designing effective systems that prioritize the recovery and treatment of discharged ammonia, mitigating potential safety concerns.
Implementation of Top-Hole Collision Risk Management for Drilling a Well with a Separation Factor Below 1.0 in a Dense Fixed Platform: A Success Story from Offshore North West Java, Indonesia
Authors: Yuda Bintang Kusuma , Sany M Fajar , Kurniawan Aris , Adi Bayu Arie Punto , Christyananta Thewa , Sirait Nikolai , Dewi Elys Irayana , Munoz David Humberto
Published: October 2024

This paper introduces a risk management strategy for a drilling campaign with a high collision risk. ELG-X was drilled from an existing platform, necessitating the wellpath to pass within close proximity of an adjacent well with an SF of 0.79. An SF below 1 poses a risk of collision due to overlapping Ellipsoid of Uncertainty (EoU), jeopardizing drilling and company's business plan. Hence, effective mitigation and directional planning were crucial for safe well execution.

A comprehensive risk mitigation strategy was developed to manage adverse consequences to an acceptable risk level, encompassing two primary activities during the drilling process. Firstly, the 12-1/4" pilot hole, typically employed for shallow gas risk mitigation, was endorsed in this case to reduce the likelihood of hole contact in the top-hole interval, with engineering mitigations including GWD utilization, high bend-degree mud motor application, passive rock bit employment, subject & adjacent well monitoring, and well integrity placement. Secondly, the 17-1/2" hole enlargement process involved maintaining drilling parameters and employing a less aggressive hole opener to prevent damage to the adjacent well.

The developed strategy was implemented during drilling in the top-hole section. The 12-1/4" rock bit, paired with a 1.83-degree bend mud motor, was utilized for controlled drilling in the collision risk interval, allowing for precision and effective maneuvering. By applying control parameters and tight survey monitoring per joint drilled, the result shows that no major indications of well collision were observed. ELG-X trajectory convincingly separated away from the adjacent well and got SF above 1. The mud motor's bend degree was subsequently adjusted to 1.5-degree, facilitating the continuation of drilling toward the casing point in alignment with the planned trajectory. Positive signs were also noted during the 17-1/2" hole enlargement, with no significant evidence of well collision or damage to the adjacent wellbore. The upcoming operations, such as running 13-3/8" casing and cementing, can be managed properly without encountering any issue or findings. In summary, the top-hole section can be secured without any safety incidents and related NPT.

This paper details the implementation of a collision mitigation strategy in the ELG-X well, Offshore North West Java Operation, serving as a valuable reference for future drilling. It showcases a successful case of top-hole drilling in a dense fixed platform with a minimum SF. The strategy is anticipated to provide insights for unlocking idle wells facing similar challenges as ELG-X.
Novel Alternative Solution for Deviated or Horizontal Geo-Steering in High and Ultra-High Temperature Reservoir, A Case from Australia
Authors: Angus Ross, , Michelle Yim, Poh Wan
Published: October 2024

Operator is developing an unconventional gas reservoir, drilling horizontal 6 1/8" production wells in an Ultra High Temperature (UHT) basin with Bottom Hole Temperature (BHT) of up to 200°C. Rotary Steerable Systems (RSS) are not commonly available with temperature rating to 200°C. Standard rated RSS (150°C) are used instead. The first well (offset well H-5) was drilled using this methodology and achieved a 1000m lateral section, however the tools were exposed to operating temperatures of 172°C. The operating temperature exceeded tool specification and resulted in significant Damaged Beyond Repair.

The operator sought an alternative solution, using robust fit for purpose steerability that would survive the high temperature environment while achieving the Minimum Acceptable Outcome (MAO) of 900m of horizontal reservoir exposure.

The contractor offered a novel solution combining technologies to drill the second (subject well) of this paper, H-4. An Adjustable Gauge Stabilizer (AGS) rated to 200°C was incorporated into a Bottom-Hole Assembly (BHA) with a UHT rated Logging While Drilling (LWD) tool rated to 200°C. This tool incorporated directional survey, gamma ray (GR), pressure-while drilling (PWD) and downhole vibration sensors. The AGS could be set to Full-Gauge (FG) or Under-Gauge (UG) diameter and the BHA was designed to drop or build inclination (respectively) depending on the setting. This provided a simple 2-D steerable assembly. UHT-rated directional, GR and PWD sensors provided directional surveys, formation correlation and downhole annulus and internal pipe pressure data. Downhole vibration sensors provided drilling efficiency data and facilitated mitigation of downhole vibration extending tool reliability.
Investigation of Applications of 3D Printing to Oilfield Equipment: A Case Study of Hydrocyclones
Authors: Zhao Xiaojie , Wang Jue , Gao Yang , Wang Wenchang , Wei Songbo , Zhou Yutian
Published: October 2024

Three-dimensional (3D) printing offers several advantages, including flexible design, faster production, cost-effectiveness, suitability for small-batch production and reduction of carbon emissions. In particular, by optimizing the structure of oilfield equipment and adjusting the microstructure of metal 3D printed parts, high-performance components can be manufactured for complex working conditions in the oilfield.

Taking the hydrocyclone as an example, the preparation process is as follows. Firstly, the optimization of the hydrocyclone's structure. The response surface design was combined with computational fluid dynamics to optimize the type and parameters of the hydrocyclone. Secondly, the selection of 3D printing material. Maraging stainless steel was chosen as the 3D printing material based on the performance requirements of the hydrocyclone. Thirdly, determining the 3D printing process parameters. Parameters were selected based on the microstructures, mechanical properties, wear resistance, and corrosion performance of the 3D printed parts. Ultimately, a novel hydrocyclone was 3D printed, and its separation performance was evaluated using a laboratory testing system.

Results show a variable pitch hydrocyclone structure with high separation efficiency was designed and a high-density hydrocyclone part was successfully printed. Heterogeneous microstructures present in 3D printing stainless steel lead to excellent strength (tensile strength, σb = 1184 MPa), toughness (impact energy, Wt = 149 J) and wear and corrosion resistance. The 3D-printed complex hydrocyclone features greatly improved separation efficiency (99.38%, which is 0.58% higher than that of the conventional structure). Based on the above results, an innovative mindset based on 3D printing for cost reduction and efficiency enhancement was formed, and a comprehensive technical system, from structural design to manufacturing, microstructure characterization and performance evaluation, was developed.

The challenges and prospects of applying 3D printing in the oilfield were analyzed, with a focus on the research and development of key oilfield equipment. This research promotes applications of 3D printing in the petroleum industry and advocates for the intelligent manufacturing of high-end petroleum equipment.
The Best Practices and Workflow of Tight Reservoir Fracturing Diagnosis, Optimization, and Productivity Evaluation
Authors: Yu Huijuan , He Zejun , Zhang Wei , Wang Meng , Xu Danian , Zhou Yongsheng , Wang Chenyang , Prabowo Ken , Gui Feng
Published: October 2024

Hydraulic fracturing (HF) is an effective technology to develop tight oil & gas reservoirs, which is expected to achieve ideal production in reservoirs that would otherwise achieve little or no production. However, it is not uncommon that many of these fractured wells are not able to achieve the expected enhancement. The objective of this paper is to demonstrate the best practices and workflow to make post-fracturing diagnosis, fracturing design optimization and pre-fracturing and post-fracturing productivity assessment.

This is a model-based approach, and the workflow is based on comprehensive understanding of geological characteristics of the reservoir. Following the general HF feasibility study, 1D geomechanical (GM) model of single well is established, then a fracturing model is built for fracturing simulation. Post-fracturing diagnosis and fracturing effect evaluation will be based on simulation results. Finally, a well flow model is established to predict productivity and conduct sensitivity analysis. In this way, the main factors affecting fracturing effectiveness can be identified and the relevant engineering parameters can be optimized.
Experimental Investigation of Infilled-Shear Fractures Conductivity in Shale Reservoirs
Authors: Lu C. , Wang S. X. , Chen C. , Li Y. Q. , Zeng Q. J. , Zhu Q. Y. , Sun J. H. , Guo J. C
Published: October 2024

The study and assessment of flow conductivity within infilled-shear fractures play a pivotal role in guiding the development of shale gas resources. This paper presents an investigation using shale reservoir rock samples from the Longmaxi Formation. We employed a novel infilled-shear seepage coupling experimental system, developed in-house, to perform nitrogen flow tests under stress seepage coupling conditions. Our findings reveal that the incorporation of proppants mitigates the impact of fracture roughness, and the effect of fracture morphology on conductivity is primarily evident at lower concentrations. The impact of shear slip on flow conductivity is discernible only in rock samples with higher roughness. Furthermore, the evolution of infilled-shear fracture conductivity with increasing proppant concentration follows a biphasic pattern: an initial decrease followed by an increase. Intriguingly, a significant positive correlation exists between the critical proppant concentration and the volume capacity, with an approximate threshold of 25%. This correlation is of profound importance for the strategic planning of fracturing operations.
Insights and Strategies for Underground Hydrogen Storage Optimization
Authors: Albadan D. J. , Delshad M. , Sepehrnoori K.
Published: October 2024

Underground Hydrogen Storage (UHS) is a promising solution for facilitating the transition to a net-zero energy landscape. Hydrogen is an excellent energy carrier that can be utilized to store surplus energy from renewable sources and later release it in periods of high-power demand. The objective of this paper is to investigate the optimal operating conditions for underground hydrogen storage and present guidelines that can enhance the utilization of the selected storage site.

The methodology of this study involves conducting numerical simulations on a synthetic model that replicates the characteristics of a heterogeneous field with two anticlines. The analysis is conducted on two cases representing a depleted gas reservoir and a saline aquifer. Key operational control parameters such as well count, bottom-hole pressure (BHP) limits, injection/production cycle duration, perforation interval, and cushion gas injection play pivotal roles. These operational parameters will be systematically varied to assess their impacts on hydrogen storage capacity, deliverability, and purity.

The results are analyzed by implementing advanced reservoir engineering practices that delineate significant differences between depleted gas reservoirs and saline aquifers in terms of storage parameters and hydrogen recovery. The proposed operational guidelines are based on water production, pressure maintenance, and hydrogen purity. Bottom-hole pressure limits are crucial well-control parameters in UHS systems. The minimum BHP limit is determined through techno-economic factors considering surface compression requirements. On the other hand, the maximum BHP limit is established based on rock mechanics and fracture gradient to ensure reservoir integrity and stability.

This paper contributes to a comprehensive framework for optimizing Underground Hydrogen Storage systems by proposing novel insights and key strategies, that can play a role in the viability and scalability of hydrogen as an energy storage solution in the transition to a sustainable energy future.
Microbial Approach – an Underutilized Sustainability Technology?
Authors: Manap A. A. Abdul , Chai I.C.C , Goodman A.H.
Published: October 2024

In an era of sustainability push, the oil and gas industry need to have a revisit of its overall strategy. In addition to profitability, sustainability is another main development driver to consider. Out of the seventeen United Nations Sustainable Development Guidelines (SDG), five are applicable to the industry (Capello et. al. 2020). They are:

SDG #6: Clean Water and Sanitation SDG #7: Affordable and Clean Energy SDG #13: Climate Action on Greenhouse Gas (GHG) Emissions SDG #14: Life Below Water SDG #15: Life On Land

Microbes are not a new focus area in the oil and gas industry, whether they contributed to favourable (microbial stimulation, EOR) and/or non-favourable (reservoir souring etc.) conditions. Microbial based technology is worth a re-evaluation since it can be considered one of the most environmental-friendly technologies available. This paper will focus on PETRONAS experience with microbial based technology studies. As we moved towards energy transition, PETRONAS is also looking into technologies which can support carbon capture, utilization and storage (CCUS) implementation and hydrogen generation. From this perspective, methane generation (methanogenesis), and subsurface hydrogen generation (dark fermentation) is worthy of consideration. The paper highlights some of PETRONAS experience with focus on microbial EOR (at laboratory and pilot scale). Methanogenesis (at laboratory scale) and conceptual biohydrogen will also be briefly touched.
An Automated Sand Deposition and Erosion Control Program: a Digital Solution for Pipeline Integrity
Authors: Dabholkar D. S. , Gupta G.
Published: October 2024

In this paper we describe the automated sand deposition prediction and erosion control advisors (SDECA) in the multiphase production network and how it enhances operational excellence and strengthens the Health, Safety and Environment vision by monitoring pipeline integrity in real-time. The SDECA is an automated advisory which runs automatically and needs minimal to no human intervention, providing operational awareness and actionable insights to decision-makers in real-time. Production fluids endure harsh ambient conditions before arriving at their distribution port. During a typical production lifecycle, every oil and gas field faces unique flow assurance challenges. Among all, sand production poses one of the most severe flow assurance risks. Large sand particles tend to settle in the pipeline forming pockets of sand beds while the small particles are carried away with fluid and causes erosion in (subsea and onshore) production facilities. Sand build-up significantly reduces operational efficiency due to higher pressure demands on the system.

The automated sand deposition prediction and erosion control advisor (SDECA) program uses a comprehensive approach to track sand deposition, sand transport along the production fluid and sand bed forming conditions by utilizing field measurements, multiphase software outputs, and the data analytics techniques. The automated erosion control program not only estimates the erosion rate in real-time, total metal loss but also identify the locations which are experiencing or have been experiencing erosional issues in complex production networks. Multiple methods are included and compared simultaneously in this SDECA program which make it robust and accurate. When the operating conditions indicate a change in the operating point outside the erosion free risk operating region and into the erosion region, the SDECA generates a warning and subsequently an alarm. These regions update automatically, depending on operating conditions and any variation in the sand production rate gets detected in the field. Compare to physical erosion monitor equipment which is typically installed at limited locations (e.g., wellhead) to provide erosion rate, this digital solution provides real-time erosion rate anywhere in the entire production network. Thus, it empowers the operators to better assess the erosion risks, allowing them to take the necessary corrective actions to mitigate or prevent failure. Currently, this is deployed at various fields with European and Asian operators, the advisory program is positively impacting OPEX by reducing downtime through early intervention and increasing uptime through real-time surveillance. New methods, combining field data, simulation data with data analytics, this automated SDECA are developed with the aim to provide faster and precise digital solutions to enhance field surveillance and pipeline integrity. This paper will also describe these methods’ development and how they have improved with time using past experiences.
Extremely Low-Frequency Electromagnetic Wave Communication Model and Simulation in Wellbore Communication
Authors: Wang Zhi , Jia Deli , Yang Qinghai , Hao Zhongxian , Chen Qiang
Published: October 2024

In recent years, the scale of oil and gas production has been continuously expanded, and processes such as layered water injection, gas injection, and oil recovery have led to stricter requirements for the precision of layered wellbore control and the distance of bidirectional data transmission. Extremely low frequency (ELF: below 30 Hz) electromagnetic wave wireless wellbore communication technology can achieve high-precision and long-distance bidirectional data transmission and overcome the problems of traditional wired communication technologies' poor pass-ability and load capacity. It does not require the addition of relays and is more cost-effective, making it a wireless wellbore communication technology with broad application prospects.

This article is based on the theory of network splitting, establishes a multi-delay and multi-weight complex network model of ELF electromagnetic waves in wellbore communication, and designs a controller. It deduces quantitative expressions for the electromagnetic field in different directions in N-layered media. The article calculates the propagation and attenuation characteristics of ELF electromagnetic waves. Deriving calculation formulas and combining simulations determines the optimal transmitting frequency range to be 5Hz to 20Hz. Field experiments have confirmed that ELF electromagnetic waves can achieve wireless communication without relays over 1600 meters. Numerical simulations are conducted to solve the distribution relationship between electric and magnetic fields in layered media, determine the coupling coefficients between transmitter and receiver, and clarify the transmission channels. Comparing the electrical signal strengths at different frequencies proves that blindly reducing the transmitting frequency is not advisable. Both theoretical analysis and experiments validate the correctness of the model. This article provides a theoretical basis and feasibility for subsequent engineering applications. This method provides a new idea for wellbore wireless communication technology in fields such as rod lifting and separated layered injection.
AI Fast-Tracking Infill Well Identification Under Uncertainty for a Complex Deep Gas Field and Accelerating Field Development Decision
Authors: Prasad D. , Patankar T. , Pandey A. , Joshi P. , Bajpai P. , Biniwale S. , Khataniar S. , Elfeel M. Ahmed , Kumar S. , Gaur P. , Kumar M. , Singh R. , Xu R. , Kumar S.
Published: October 2024

Objective/Scope

R’ field is a tight, deep gas-condensate volatile-oil reservoir, in a geologically complex volcanic depositional setting. Vertical and deviated wells penetrate several zones, multi-stage fractured making it commercially viable. Ramp-up and sustaining production at the planned plateau production rate through intensive development drilling campaigns was a challenge. The primarily transient production profiles and recoveries per well are highly variable and the identification of sweet spots and good quality reservoirs(pay) is fraught with uncertainty. There was an urgency to fast-track optimized drilling schedules that maximize return on investment while sustaining production. This called for both a better quantification of risks and a higher speed in subsurface modeling and field development planning.

Methods, Procedures, Process

An integrated reservoir modeling workflow with probabilistic dynamic model calibration approach was designed for uncertainty quantification and sweet-spot identification. The static and dynamic models maintained a high resolution to retain fidelity and allow precision in modeling the hydraulic fractures, and phase behavior effects. The geological and completion uncertainties number exceeded 1500, however fast simulation algorithms on high performance computing was leveraged to process multiple realizations. A high-fidelity simulator capable of modeling time-variant, bi-wing multistage fractures at a field scale, Machine Learning (ML) proxies of the dynamic simulation models were the innovative technologies utilized to make the uncertainty workflow practical and affordable. The ML proxies were used to screen and rank uncertain parameters and generate posterior probability distributions used to sample representative models for planning purposes. Probabilistic maps of connectivity were generated using streamline simulation to guide both history-matching and well-placement activities. Decision criteria were developed that integrated model-based technical and economic risk attributes with other analytical attributes to help screen and rank well locations with the high potential and lowest risk.

Results, Observations, Conclusions

Novel/Additive Information

An innovative approach of ML-assisted history matching and probabilistic forecasting without compromising the model fidelity proved invaluable. Collaborative and agile approach of rapid prototyping and power of cloud computing enabled evaluation of 1000s of field development scenarios and thereby fast-tracking the decision-making process.
Experimental Study on the Acid-Etched Fracture Conductivity of Novel Nano Retarded Acid System
Authors: Cui Bo , Rong Xinming , Guo Buming , Feng Puyong , Li Xiang , Wang Shun , Wu Guang
Published: October 2024

The novel nano retarded acid system has merits of low viscosity and strong retardation, which overcomes the challenges of high friction pressure of emulsified acid and polymer residue damage of gelled acid and has been widely used in carbonate acidizing in China offshore Oilfield. However, the acid-etched fracture conductivity is not clear. The paper researches the acid-etched fracture conductivity of nano retarded acid in low-permeability carbonate reservoirs to guide acid fracturing onsite application effectively.

The smooth rock plate and rough rock plate are taken as experimental objects. The gelled acid and emulsified acid are used as comparative acid systems. Acid-etched fracture conductivity, surface morphology scanning, and continuous strength testing equipment are used to study the effects of acid type, alternating injection stage, injection rate, viscosity ratio, reaction time, and rock plate type on fracture conductivity. Through experimental study, construct characteristic parameters of high acid-etched fracture conductivity, establish the relationship between acid fracturing technical and acid-etched fracture conductivity, and clarify the mechanism of nano retarded acid differential acid etching and alleviating rock plate strength damage.

Results from the lab study indicated that the nano retarded acid system is a new type of acid system with nanostructure, low viscosity, low damage, low friction, and strong retardation performance. Compared with gelled acid and emulsified acid, nano retarded acid can form a strong channel etching morphology, which has a high differential dissolution and low rock plate damage strength and can maintain high conductivity under high closing pressure. Increasing the number of alternating injection stages, injection rate, viscosity ratio, and initial surface roughness of the rock plate for nano retarded acid system can help to form a dominant acid flow channel through differential acid etching. This research on nano retarded acid fracture conductivity can provide effective guidance for field application.
Structural Design of Fixed Jacket-Type Offshore Platforms – A Disruptive Technique
Authors: Chatterjee Prabir Kumar
Published: October 2024

This paper presents a semi-empirical method to automatically configure, size and carry out the preliminary design of a fixed offshore platform considering only a few basic input parameters when topside details are unavailable. Input parameters include the water depth, maximum wave height, design seismic coefficient, functional type of the offshore platform, a rough estimate of the gross topside weight (other than the structure), the number of well conductors and the available information on piles axial capacity. The main objective of the present work is to create a design and produce material take-off (MTO) that is sufficient for tender documents. The computer program developed for the above purpose generates a detailed analytical model incorporating available knowledge on equipment layout and structural design. The program creates a design without actually carrying out any structural analysis and generates the MTO based on the model created by the program. Structural design of real-life offshore platforms generally passes through several changes during the course of preparing a final design. The most common changes occur due to the requirement of additional deck space identified during model reviews, major revision in equipment layout and detailed material handling studies. In some cases, structural design is influenced by the equipment layout preferred by the owner/operator. The method adopted here will minimize, if not eliminate completely, the subsequent changes in the structural details unless a significant change in the topside facilities is encountered. As expected, a number of different structural designs can exist for the same input data. The most important advantage is the immediate availability of the structural analytical model for subsequent detailed analyses and initiates a 3D model for other engineering disciplines to build up equipment, piping, utilities, etc.