bluuebunny/crossref_metadata_2025_split huggingface dataset:
Modeling and Analysis of Pressure- and Rate-Transient Behavior of Interfering Horizontal Wells in Multi-Layer Unconventional Reservoirs
Authors: Makhatova M. , Ozkan E. 
Published: September 2024

AbstractMulti-well systems are essential for unconventional asset development by optimizing the reservoir drainage, well productivity, and cumulative recovery to maximize the economics of the project. Although the underlying principles of infill drilling and multi-well production is the same as that for conventional reservoirs, in unconventional reservoirs, the contrast between the stimulated and unstimulated volumes (SRV and ORV, respectively) of the reservoir, differences in well completions and resulting SRV vs. ORV properties, asynchronous start of production, different production conditions, and unmatching schedules of production and shut-in periods further complicate the design (the spacing, completion, and production conditions) of the multi-well systems. Moreover, development decisions are usually made with uncertainties caused by the complexity of well-interferences in the existence of extreme reservoir heterogeneity. Therefore, to make multi-well unconventional reservoir development decisions, both the knowledge of the interwell reservoir characteristics and their effect on the multi-well productivity of the system must be known. These requirements call for models that are accurate and efficient for estimating reservoir and completion parameters by pressure- and rate-transient analysis (PTA and RTA, respectively) and capable of efficiently evaluating multiple development scenarios subject to the uncertainties of reservoir characteristics.We have developed robust semi-analytical models to analyze the performances of multi-well systems in single and multi-layer completion conditions in unconventional reservoirs. This paper discusses the diagnostic features of pressure- and rate-transient behaviors of multiple wells in single- and multi-layer unconventional-reservoir, delineates the sensitivities of well performances to well spacing, stimulation treatment, and production conditions of interfering wells, and demonstrates the application of the models to PTA and RTA of field cases. The PTA/RTA methodology presented in this work consists of obtaining initial estimates of the well completion and reservoir properties through diagnostic and straight-line analysis of specific flow regimes, guided by the multi-well solution, and refining the estimates by matching the transient well responses by the semi-analytical model. This methodology provides a remarkably efficient and reasonably accurate estimation of properties within the bounds of the system uncertainties.
Trends in Academic Research and Graduate Education in Petroleum Engineering Programs
Authors: Fahes M. , Al-Shalabi E. W. , Hoffman T. 
Published: September 2024

AbstractUndergraduate education in Petroleum Engineering (PE) has survived the latest downturn in the industry, and enrollment has started to show an uptick in numbers. Anecdotal evidence, however, has been hinting at a different trend in graduate training and academic research. In this work, the authors collected and analyzed data, on US-based petroleum engineering departments, that included over $137M in external research funding and over 1,900 thesis/dissertations over the span of ten years, in addition to over 1,100 publications from these departments in 2023. The data was analyzed through classification into different categories, including Reservoir/Production, Fracturing, Drilling, Non-Fossil Fuel Geoenergy (geothermal, CCS/CCUS, hydrogen), and Others. The results reveal a drastic shift in research and graduate training that is expected to significantly impact the future of these departments and the workforce they train. The findings show a drop of 70% in external funding supporting oil and gas research over the past ten years, and a growth of 230% in funding for non-fossil fuel topics. This transition is shown to have impacted the topics represented in theses, dissertations, and publications. The findings call for strategic discussions around alignment between the needs and the trajectories in this domain.
Research on the Influence of Natural Fracture Development on the Deep Shale Gas Well Fracture Network Construction in Southern Sichuan
Authors: Peng Sirui , Zhao Jinzhou , Ren Lan , Lin Ran , Zhou Bo , Wu Jianfa , Song Yi , Shen Cheng 
Published: September 2024

Abstract
The Sichuan Basin, China's largest shale gas development region, encompasses the natural fracture-rich Luzhou Block. The high-density non-uniform natural fractures in this area significantly influence the construction quality and efficiency of deep shale gas horizontal wells. Research indicates that the mechanical properties and spatial distribution of these natural fractures affect the propagation and diversion of hydraulic fractures, but the governing laws remain to be fully elucidated. This study categorizes the Luzhou Block's naturally fractured areas into six types based on their development characteristics and relative positions to horizontal well sections. Furthermore, it introduces a method for morphological inversion of shale gas well fracture networks using microseismic monitoring data. This method was applied to 24 deep shale gas wells in the Block and combined with the six types of naturally fractured areas, the above underlying influence mechanism was derived. Then it reveals how naturally fractured areas with different characteristics influence the fracture network morphology and complexity and analyzes the relationship between fracture network quality and well production. The results demonstrate that during the hydraulic fracturing process in deep shale gas reservoirs, the development areas of natural fractures can capture or intercept the fracture network, obstructing its expansion behavior, reducing its area and complexity, and ultimately leading to a decrease in gas well production. In particular, when a small-angle, large-scale naturally fractured area develops near the wellbore, the hydraulic fractures will quickly propagate to this area. After activating and communicating the natural fractures, it may cause rapid fluid filtration and a sharp drop in the net pressure within the fractures, severely impacting stimulation performance. It suggests that adjusting construction parameters appropriately may mitigate the adverse impact of natural fractures on the fracturing effect. These findings clarify how naturally fractured areas with different development characteristics affect stimulation performance and offer insights and references for designing and optimizing deep shale gas well fracturing technology.
ScCO2 Foams for Geothermal Reservoirs’ Stimulation: Impact of Fracture Roughness and Temperature on Rheology
Authors: Samarkin Yevgeniy , Prodanovic Maša , DiCarlo David , Tajik Abdul Raouf , Wileman Angel 
Published: September 2024

Abstract
Applications of foams as fracturing fluids have gained a significant interest over the past few decades. Foams possess several advantages over regular fracturing fluids, such as flexible rheology, better mobility control, and reduced water utilization. While the flow of foams in porous media has been extensively studied, their performance in fractures remains partially unclear. This research aims to expand this knowledge and discuss potential applications of foams for the controlled stimulation of geothermal reservoirs.
The experimental work for this study involved utilizing granite rock samples, saw-cut into halves to mimic fractures. A spacer was used to keep smooth fractures open during experiments, while rough fractures were generated by modifying the rock surface using a sandblasting technique. The performance of the supercritical CO2 (scCO2) foam (65-90% quality), represented by its viscosity, was tested in rough and smooth fractures at 1200 psi pressure and temperatures ranging from 90°C to 150°C via multiple core flood experiments.
The study revealed that foam viscosity drops considerably as temperature rises, with a reduction of over 2-fold observed beyond 90°C. Additionally, foamability decreased at higher temperatures, resulting in less and weaker foam at the same flow rates compared to lower temperatures. However, injecting foam at higher flow rates improved foamability at elevated temperatures. Moreover, the roughness of fractures had a positive, though less significant, impact on foam rheology than anticipated. In some cases, roughness improved foam generation, while in others, smooth fractures yielded better results.
The outcomes of this study provide more detailed insights into the performance of foam under high-temperature conditions. A better understanding of foam behavior in rough and smooth granite fractures at high temperatures further expands its potential applications in geothermal reservoirs for controlled stimulation.
Barrier Design and Evaluation Process to Achieve Cement Integrity in CCS Wells
Authors: Jandhyala Siva Rama Krishna , Lewis Samuel J. 
Published: September 2024

Abstract
Barrier design processes for oil and gas wells have historically demonstrated their benefit in risk reduction and cement design optimization when using Portland cement. Carbon Capture and Sequestration (CCS) wells have a different set of risks which must be considered. These risks are a consequence of mechanical, thermal, and hydraulic loads acting on the barrier which is also undergoing mechanical changes due to chemical alteration in the case of Portland cement. Such changes are a function of time, CO2 state, cement composition, temperature, and pressure. The specifics depend on the use case, for example a plug, an annular sealant, a monitoring well, or an injection well. The goal of any risk assessment is to determine whether the above-mentioned events will compromise the barrier. Given the chemical and mechanical changes occurring in a Portland cement barrier, there is a need to tailor existing barrier design processes to suit CCS wells and account for this alteration.
The proposed design process comprises of four steps. The first step will assess the extent of the reaction between CO2 and the cement sheath under downhole conditions. The second step will determine the reaction driven changes to the mechanical properties of the cement sheath. Such changes may occur throughout the cement or only in a portion of cement depending on the location and injection plans. The third step will use the modified properties and determine the stresses and temperatures in the cement sheath under the action of temperature and pressure loads. The fourth step will determine the risk of mechanical failure by calculating operational loads and applying them to the altered cement. If the failure risk is too high, the cement composition can be iteratively tailored to determine an acceptable design.
The first two steps are enabled by experimentally generating CO2 exposure data on multiple cement systems and exposure conditions. Data for alteration rates, physical changes, mechanical changes, etc. are gathered in order to build semi-empirical models that can predict the effect of CO2 based on the cement system design over time. The third step utilizes existing wellbore stress modelling software and incorporates the spatially varying mechanical property inputs determined by the alteration models. Stresses from the third step are compared with predicted failure properties (compressive and tensile strengths) to assess the risk of loss of cement sheath integrity.
The proposed design evaluation process describes the chemical and mechanical events unique to CCS wells. Consequently, it will provide a vital tool to the industry for tailoring cement compositions and minimizing risk of loss in cement sheath integrity in a dynamic CO2 environment.
The Effect of Fluid Content and Effective Stresses on Stick-Slip Friction in Rocks: Implications for Induced Seismicity
Authors: Sathyanath Arun , Sharma Mukul M. 
Published: September 2024

Abstract
Induced seismicity has become a serious issue in many unconventional plays in the US. These events are primarily associated with the injection of large quantities of produced water at very high rates. It is well known that the frictional properties of rock joints have a large influence on such induced seismic events during wastewater disposal in sub-surface formations. The primary objective of this study is to understand the role of pore fluids, in-situ stress, fracture roughness and pore pressure on the shear failure of rock fractures.
A new triaxial apparatus is developed that allows us to measure the frictional properties of fractures under different loading and pore pressure conditions. This apparatus can independently control the pore pressure, shear stress, and normal stress acting on the fracture surface. The frictional properties of rocks and the fracture permeability after a slip event were estimated by keeping the net shear stress and normal force applied on the rock constant. The experiments conducted allow us to directly measure stick-slip and dynamic friction coefficients as well as the creep that occurs after frictional sliding. Tests are conducted with both air and brine as pore fluids. The shear stress is gradually increased, and the displacement of the fracture surfaces is measured. The effective normal stress and pore fluid are varied to measure the impact of these parameters on both stick-slip and creep frictional sliding.
The results from the experiments clearly show that the rock surfaces slide in a combination of sudden jerky motions (stick-slip events) and of smooth, gradual movements (creep deformation). The frequency and magnitude of the stick-slip events are important since it is these events that are primarily responsible for induced seismicity. Changes in the effective normal force acting on the fracture mimics the change in pore pressure with water injection. When the shear stress acting on the fracture surfaces overcomes the strength of asperities preventing the sliding, stick-slip sliding begins followed by smooth sliding. Creep deformation is measured as the shear stress and the pore pressure are held constant and the fracture surfaces continue to slide.
The coefficient of friction gradually increases as the shear stress increases and the surfaces repeatedly slide over each other. The friction coefficient reaches a plateau value of about 0.6. The effective normal stress or the type of pore fluid has very little influence on this stabilized value of friction coefficient. The friction coefficient appears to be primarily controlled by the roughness of the fracture surfaces. The number and magnitude of stick-slip events is significantly larger when air is the pore fluid (rather than water). This clearly implies that the composition of the pore fluid impacts the likelihood and magnitude of induced seismicity. The magnitude of the stick-slip events also increases as the effective confining stress increases.
Unconventional Solutions to Cure Severe-Total Lost Circulations – Field Applications from Middle East
Authors: Savari Sharath , Kerkhoff Erik , Ismail Ahmed , Nasrallah Mena , Bashandy Tamer 
Published: September 2024

Abstract
Curing severe to total lost circulation in naturally fractured/vugular formations has always been challenging, especially across the Middle East. In these environments, conventional particulate lost circulation materials (LCMs) are seldom effective due to the uncertainty on the sizes of the formation openings through which losses occur. This paper presents lab evaluation data, supported by field experience, of using a combination high fluid loss squeeze (HFLS) and reticulated foam LCM (RFLCM) treatment.
The LCM treatment was designed and qualified based on successful laboratory tests sealing slots up to 40,000 microns. Laboratory and field results are presented from the dual HFLS and RFLCM technology application in two countries in the Middle East: Oman and United Arab Emirates (UAE). The details include formation characteristics, hole size, LCM pill volume and concentrations, and the mixing and pumping methodologies used. The success of the applications is demonstrated by presenting the loss rates before and after applying the treatments, in static and dynamic wellbore conditions, and illustrates savings in terms of rig time.
In Oman, the subject wells experienced static losses up to 125 bbls/hr and dynamic losses in the range of 280 bbls/hr (at 550 gpm) to "No returns". The formation was characterized as vugular, and the client's objective was to pump an efficient LCM solution that would cure losses quickly after reaching well Total Depth (TD) and perform logging operations without having to use a cement plug thereby saving rig time. The HFLS and RFLCM treatments were mixed in water, pumped through a circulating sub and a hesitation squeeze was applied. After the squeeze, both static and dynamic loss rates reduced to zero and operations were able to safely continue.
For the UAE applications, the subject wells were drilled with non-aqueous fluid and losses experienced were in the range of 85-200 bbls/hr in static conditions, and 150 bbls/hr to complete losses in dynamic mode (990-1250 gpm). The formation was characterized as naturally fractured. The HFLS and RFLCM components were mixed in base oil, pumped through a circulating sub and a hesitation squeeze method was applied. After the squeeze, static losses reduced to 2-15 bbls/hr and dynamic losses to a maximum of 25 bbls/hr (dropping down to 5 bbls/hr while drilling) allowing operations to recommence.
In technical qualification tests, plugging of a 40,000-micron lab-simulated fracture/vug opening provided confidence that the subject LCM combination would deal with losses to uncertain fracture/vug size downhole. The successful field applications where severe to total losses were cured has validated the HFLS / RFLCM dual approach. The most notable advantage of improved LCM technology is the reduction in well construction costs through decreased rig time associated with curing severe to total lost circulation.
Determination of Production Potentials of Geothermal Resources for Rapid Exploration and Development Decisions
Authors: Jin Guodong , Kwak Hyung T , Yousef Ali A , Banaja Hussam H 
Published: September 2024

Abstract
This paper presents a semi-analytical wellbore heat flow model coupled with a formation heat conduction model for rapidly determining output potentials of thermal energy from the open-loop and closed-loop geothermal systems. Energy conservation equations are used to simulate thermal flow dynamics of fluids inside the wellbore, while heat diffusion equations govern the transient heat transfer in the formation. A semi-analytical technique is used to solve these coupled equations iteratively. Model validation was done by comparing the semi-analytical solution with numerical simulation results on a 3D wellbore model for a coaxial closed-loop geothermal system. Good agreement of the temperature profile along the wellbore was observed between the semi-analytical and numerical results.
Production potentials of thermal energy depend on the geothermal systems selected to extract the heat from the reservoir. Closed-loop systems rely on the circulation of a working fluid to absorb and transport heat to the surface. Their heat extract efficiency depends on the mass flow rate and initial injection temperature of the working fluid. The higher flow rate leads to a lower fluid temperature but a higher thermal energy output at the wellhead. As the injection fluid temperature increases, the energy output decreases but the output fluid temperature increases. Open-loop systems produce the hot reservoir fluid directly to the surface, in which an increase in the flow rate would increase the fluid temperature and thermal energy production at the wellhead. As the production continues, thermal energy output decreases faster at the beginning and reaches a plateau in the long run. Compared to numerical models, the semi-analytical requires minimal inputs to generate the compatible outputs with higher computational efficiency, which is preferred in many applications, in particular for energy resource screen analyses of new geothermal prospects or repurposed oil and gas wells.
Reduce Costs by Improving Reliability and Extending Mean Time Between Failure MTBF in a Harsh Electric Submersible Pump-Lifted Field
Authors: Luis Enriquez , Carlos Reyes , Johanna Gallegos , Richard Torres , Gary Tagarot , E Batallas , Jorge Villalobos , Alvaro Correal , Juan Pancho , Kevin Andagoya 
Published: September 2024

Abstract
This paper presents a case study that includes the steps taken to improve the reliability of the artificial lift systems in a field of application. It is shown through the increase in the mean time between failures (MTBF) from 489 to 1,000 days and the decrease in the failure index from 0.47 to 0.24 over 5 years of continuous work.
An important challenge in the field of study was the high number of electric submersible pump (ESP) failures over 90 failures per year which caused losses over 500 Kbbl of oil per year and required around of 65 MMUSD to recover their production through workover activities. An integrated continuous improvement approach was applied by identifying the issues, proposing solutions and measuring results.
After the implementation of all the actions mentioned in this document, the MTBF was duplicated, the failure index was reduced 51% for ESP, 25% reduction in ESP-related production losses; plus 40% reduction in workover jobs which saves 26 MMUSD each year. Another benefit is reducing about 900 Tons of CO2 emissions thanks to less usage of diesel for workover jobs.
This document shows three sections which summarize: 1) The initial diagnostics, 2) Actions for improvement, and 3) Results. These three sections include four areas of focus: i) Data Management, ii) Culture and Organization, iii) Technology, and iv) Processes and KPI.
At the end of the document the reader will find the conclusions which show how a proper diagnostic can direct focused actions like the creation of a performance dashboard together with an organizational culture towards continuous improvement, and the associated benefits once the process is fully implemented.
First Global Deployment of Level-5 System with Dual ESP in Offshore
Authors: Alsaihati Zainab , Balseiro Prudencio , Juaid Faisal , Alghamdi Mohammed 
Published: September 2024

Abstract
This paper presents the success story of the first worldwide implementation of a Level-5 multilateral completion system, fiber optics permanent downhole monitoring system (PDHMS), and dual electrical submersible pump (ESP) upper completion in an offshore environment.
The project took place on an offshore dual-purpose evaluation and producer well consisting of a pilot hole and a horizontal lateral across the reservoir section. The pilot hole was drilled with a maximum inclination of forty-five degrees, where required logs were collected. Then, a seven-inch liner was set and cemented to enable future reservoir surveillance. Successful deployment of complex completions requires meticulous planning among a multidisciplinary team. Preparation for logistics and standardization of the operating procedures among all involved parties was an essential key to the success of the project.
The state-of-the-art completions enabled full access to the pilot hole for future intervention to monitor the reservoirs behind the seven-inch liner in the pilot hole. Additionally, the Level-5 system provides a hydraulic isolation of the lateral junction to avoid potential water cut during the production phase. Furthermore, the purpose of completing the well with dual ESP is to extend the life of ESP by alternating the ESP operation periodically, which will, consequently, minimize workover intervention to replace ESP. In addition, the most beneficial advantage of using dual ESP completion is that it prevents shutting down the oil production while waiting on a workover rig to replace ESP.
The novelty of the completion described in this paper is the combination of running a Level-5 completion system, fiber optics PDHMS, and dual ESP with upper and lower Y-tools. Such utilization of intricate tools in one well was unprecedented globally.