bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of Simulation Software to Enhance Filter Cake Breaker Placement
Authors: Govinathan Kesavan , Jain Samyak , Balasandran Anandhadhasan , Yeo Kim Teng 
Published: February 2023

AbstractPlacement of a delayed filter cake breaker fluid system is usually carried out during the lower completion phase of a well development. Whilst the fluid system would undergo extensive testing during its design phase, the objective of achieving a good clean-up of the target interval requires both testing and an optimum placement strategy. A good clean-up improves the possibility of achieving the desired production rates when the well is put on production.Placement of the treatment should always be performed below the fracture pressure. If that limit is breached during pumping of the treatment, it can induce losses which would likely result in poor and non-uniform breaker placement and potentially a well control issue. Detailed pre job design and planning using a sand control simulation software allows improved insight and precision to the placement strategy. It also facilitates a better understanding of the completion optimizations that can be incorporated prior to the breaker treatment. This allows the treatment to be kept below fracture pressure and control the losses to the formation.The use of the software for this application was found to be very effective to optimize pumping rates and manage dynamic pressure limitations using well and completion data. The simulation software was utilized to evaluate multiple scenarios with variable input parameters and the results were analyzed to provide valuable insight into the impact this has on the pumping pressure and equivalent circulating density (ECD) margins.The paper presents examples of how the breaker treatment design strategy was optimized using the simulation software. Comparison of the modelled and actual data is presented to confirm accuracy and demonstrate how the model can be used to further optimize the design for future operations.
A Successful Field Trial of a New ASP Technology in a High Water Cut and High Recovery Degree Reservoir After Polymer Flooding in North China
Authors: Wu Xingcai , Zhu Yan , Liu Xiaoying , Zhang Song , Gao Shang , He Jingang , Wu Hao , Wang Chunyao , Ye Yinzhu , Cui Guoyou , Lu Qiong 
Published: February 2023

AbstractLarge scale polymer flooding in Daqing Oilfield achieved great success. The average recovery degree of these oilfields after polymer flooding has reached 52.5%, and the average water cut has reached 96.0%. It is urgent to find an effective technical method for further EOR. Targeting the highly dispersed remaining oil in the post polymer flooding reservoirs, the continuous phase polymer solution in ASP technology was replaced by nano-micron particle polymer dispersion to realize optimization for EOR mechanism, so the ASP technology was upgraded. The field test, has been completed the slug injection, and achieved obvious EOR effect.The ASP slug design with HPAM solution as the main displacement phase was abandoned. A type of water dispersion of nano-micron particle polymer as the main displacement phase was designed to replace the "P" in traditional ASP slug, so that the flowing control mechanism of "P" was optimized. Through synchronous diversion and displacement, it can initiate and sweep the remaining oil dispersed in relatively small pores. A large three-dimensional physical model with the size of 60 × 45 × 4.5cm was made to simulate the real development history of water injection and polymer flooding of the reservoir, based on which, the performance of the upgraded ASP was modeled. Furthermore, the program was designed and optimized by numerical simulation.The physical simulation fitting experiment of the development history of water flooding and polymer flooding shows that the coincidence rate is 93%+. After polymer flooding, the upgraded ASP further improved the recovery by 15.2 percent. The optimized scheme of numerical simulation is to inject 0.5PV of new ASP slug. Under the precondition of the historical recovery degree of 55.8% and water cut of 98.44%, the new ASP is expected to improve the recovery by 7.9% within 10 years. At present, the field test of ASP slug injection has just been completed, and remarkable results have been achieved, The daily oil production has increased by 60%, and the water oil ratio has decreased from 61.9 to 38.4. The daily oil production of some producers has increased by 2 to 3 times, and the recovery has increased by 5.2%.The field trial proves that the oil displacement mechanism of nano-micron-particle-polymer ASP flooding chemical system is more advanced and the displacement efficiency is higher than that of the traditional ASP flooding, and the oil recovery can be further enhanced for similar reservoirs under extreme conditions after polymer flooding. The traditional ASP technology is expected to have great upgrading and developing.
Insights from Application of Elastic Full Wave-Field Inversion in Clastic and Sub-Salt Settings.
Authors: Routh Partha , Baumstein Anatoly , Cha Young Ho , Nayak Soumya , Wang Haiyang , Tang David , Barr Jay , Martinez Alex 
Published: February 2023

AbstractElastic Full wave-field (eFWI) inversion is aimed at inferring physical properties of the subsurface directly from seismic data. Goal is use highest level of physics to produce reliable properties to impact upstream business decisions. We focus on elastic parameters particularly the ratio between pressure (P) and shear (S) wave velocity, Vp/Vs that can be indicative of the type of fluid present in subsurface reservoir and P-wave impedance, Ip to impact porosity estimation.Our eFWI methodology derives the wavelet directly from seismic shots rather than using well information. Using field examples we explain the eFWI workflow, outline key steps and provide analysis of the results. The first field example is from a structurally simple clastic setting. The second field example is from a complex sub-salt environment and is focused on differentiating net versus non-net in pre-salt carbonate reservoirs - a challenging problem when using narrow azimuth streamer data. The third field example is from a clastic setting and uses well information to scale the wavelet and is applicable in development and production settings.Our experiments with the two exploration style field examples show that it is possible to directly invert shot data to obtain geologically meaningful elastic properties useful in exploration and early development phases. However, challenges remain. The inverted Ip has higher fidelity compared to the Vp/Vs ratio. In fact, Ip is sufficiently accurate to be reliably used for porosity prediction. The eFWI Vp/Vs inversion results are only in qualitative agreement with well information (as a blind test) for the clastic example, but sufficient to discriminate the net versus non-net for the pre-salt example. A qualitative match may be insufficient to determine fluid type via rock property inversion without any well control. In an environment without well control, further research is needed to investigate the sensitivity of Vp/Vs and determine if data quality is a key factor, in addition to stabilizing the extraction of elastic parameters in a multi-parameter inverse problem.The novel aspect for our approach is in developing a practical eFWI methodology in 3D and working with raw seismic shots with very minimal processing. Examples from different geological settings and use of well versus no-well provide valuable insights into current application space and potential research direction on improvements to eFWI algorithm.
Success Story of the Development of Extremely Low-BTU Flare Tip Technology
Authors: Assavanives Boonyakorn , Watanakun Kantkanit , Amarutanon Nunthachai , Kodesh Zach , Muangsuankwan Natthasart , Watcharasing Sunisa , Sinthavarayan Kanokporn 
Published: February 2023

Abstract
Current low-BTU flare tip technologies require a flare gas lower heating value (LHV) of approximately 200 BTU/scf while significant advancement on CO2 removal membrane technology has resulted in an extremely low-BTU waste gases having LHVs around 140 BTU/scf. This requires the extremely lean waste gas to be supplemented with methane to raise its heating value to achieve stable combustion. Not only does the operator lose the benefit of the advanced membrane technology but they also lose product (sellable gas) and have increased green house gas (GHG) emissions at the production site. Consequently, the development of the "Extremely Low-BTU Flare Tip" is beneficial in multiple ways. The Extremely Low-BTU Flare Tip development project was launched as a joint research and development project between PTTEP and John Zink Hamworthy Combustion (JZHC). The innovative design is based on theories behind low heating value gas combustion and improves upon existing low-BTU flare technology. The goal was to obtain flame stability and safe operation in offshore oil and gas production environments at LHVs significantly lower than 200 BTU/scf. This project included multiple iterations of prototype design, simulation, and testing, with various parameter adjustments to optimize the performance against completeness of combustion criteria. The design was studied through computational fluid dynamics (CFD) simulation and prototype testing to develop the operating envelope of the Extremely Low-BTU Flare Tip. The design of the tip integrates John Zink's existing technology with additional components i.e. spokes and top hat. CFD simulation was performed to observe the fluid behaviors, including temperature, velocity, and unburned hydrocarbon; allowing modification of the design prior to the fabrication of the prototype. The final design has been proven by a series of prototype tests to reinforce the level of confidence in its performance and mechanical integrity. The test results show that the Extremely Low BTU Flare Tip has the capability to combust flare gases with an LHV as low as 110 Btu/scf which is a significant improvement over existing flare tip technology. The benefit of this technology is estimated to be between 10-31 MMUSD per year per platform, depending on the lowest achieved heating value. The success of the Extremely Low BTU flare tip development project provides a breakthrough technology which is not limited to brownfield applications but also supports future acquisition and development of Greenfield sites. This Extremely Low BTU flare tip technology will improve the probability of success for greenfield development with a high CO2 reservoir by maximizing reservoir recovery, optimizing overall capital and operational expenditure, and minimizing hydrocarbons flared which has the direct effect of increasing gas sales and decreasing greenhouse gas emissions.
Forecasting Energy Demand and CO2 Emissions for Crude Extraction and Separation Using Machine Learning
Authors: Abbas Muhammad , Naeem Omar 
Published: February 2023

AbstractWith the drop of oil reservoirs’ natural pressure, and injection of higher amounts of water, predicting energy consumption required to extract multiphase hydrocarbon product, and separate it into crude, gas, and water has become a challenging and more dynamic problem. This paper discusses a detailed technique to forecast energy demand for water injection and Gas-Oil Separation Plant (GOSP). Key elements of the method include identifying the energy, products, and feed streams, along with other parameters impacting the energy demand. The relationships among all independent and dependent variables are identified, along with the consideration of ambient conditions and equipment operating efficiencies. Machine Learning (ML) algorithms are then applied, using available industry software, to build and improve these relationships using the historical data. The best-fit forecast models, also called champion models, are selected that provide the least variance from actual data. These models can be updated, using the software, as the new data is received and variance between predicted and actual energy increases. The forecasted energy demand is converted to CO2 emissions using the conversion factors for fuel gas and power. The forecasting results and underlying process can be converted into dashboards for visualization and utilization by the users of operating plants. The method described in the paper is novel and first of a kind for predicting energy demand and CO2 emissions for a GOSP considering increases in water cut and water-injection.
Encapsulated ESP System: An Innovative Solution for Extended Run Life in High H2S Environments
Authors: Alghamdi Anwar S. 
Published: February 2023

AbstractThe electric submersible pump (ESP) is one of the most reliable artificial lift methods for delivering high flow rates in oil wells. If well designed for reservoir properties, ESPs may run for several years before failing. Despite many ESP design advancements, electrical connections remain within the most prominent points of failure in high H2S environments. This paper presents an innovative approach to mitigate electrical connection failures by encapsulating the ESP system for extended ESP run life in high H2S environments.Following an ESP design review to explore current practices in mitigating ESP electrical-connection failures in sour wells, an innovative ESP system was designed to eliminate electrical-connections’ contact with well fluid. The ESP is connected from the top to a production tubing, encapsulated within a pressure-retaining pod, and located above a deeply set production packer. The motor head is designed to partially set outside the pod to accommodate electrical-cable connection, while partially encapsulated within the pod to deliver the necessary electrical supply to the ESP motor. The tubing-casing annulus (TCA) is then filled with inhibited-brine to protect the electrical connections.Experts in the field typically select special ESP metallurgy and electrical connections (i.e., metal to metal) in high H2S wells to extend the run life of ESP systems. Although the development of multiple versions of electrical connections can mitigate H2S attacks, field experience has shown progress in sour environments where ESP run life is not yet matching mild environments. Most efforts were made to minimize H2S attacks on ESP electrical-connections by developing robust ESP systems, but little to no effort was made to eliminate the risk. This challenge can be undertaken by encapsulating the ESP system to avert electrical connection contact with well fluid. Thus, it provided a radical solution to one of the most common ESP failure points in sour environments.The encapsulated ESP system is a new concept, for which a patent is pending, designed to address electrical connection failures for an extended run life in high H2S environments. This paper will discuss the background and design of the system and its potential to eliminate electrical connection integrity issues.
Analysis of Circulating Pressure and Temperature using Drilling Microchips
Authors: Li Bodong , Zhan Guodong , Okot Michael , Dokhani Vahid 
Published: February 2023

AbstractAccurate knowledge of circulating pressure and temperature is essential for making critical decisions while drilling operation. Through implementation of miniaturized semiconductor technology, we obtained near real-time dynamic pressure and temperature profile of the wellbore, making previously simulated critical operational data such as equivalent circulation density (ECD) and wellbore thermal distribution now measurable using drilling microchip. The application of drilling microchips to collect distributed pressure and temperature data while drilling is investigated, where each microchip measures both pressure and temperature simultaneously. This study also presents a revised method to calibrate measurements of drilling microchip with depth.Four field trials were attempted in a slightly inclined well using water-based or oil-based muds, where 10 drilling microchips were deployed in each trial. The recovered data from the drilling microchips are first downloaded and compiled. An in-house software is developed to process and convert time-scale of each drilling microchip to depth considering slippage of drilling microchips in drill string and annulus. An iterative algorithm is designed to calibrate the predicted arrival time with the actual arrival time of each tracer, which ultimately yields the true velocity of tracers in flow conduits. The maximum measured pressure is used as an indicator to locate each tracer at the bottom hole. It is realized that a plateau of pressure versus time can signify a trapped tracer in the flow path if the pump rate was maintained constant.The results of field trials show that some of the tracers were trapped for few minutes in the lower section of annular space or before the bit nozzle. The results of temperature profiles conclude a unique pattern for almost all of the deployed drilling microchips. However, the results of pressure profiles can be classified in two different groups as drilling microchips could have moved in different batches while pumping. The calculated temperature gradients show a heating zone near the bottom hole and continuous cooling of drilling fluid as tracers move toward the surface. The average pressure gradient is in the range of 0.52 – 0.61 psi/ft among different trials. It is shown that the velocity of tracers in each interval strongly depends on the flow regime.To our best knowledge, a combined measurement of circulating temperature and pressure using drilling microchips for the first-time is successfully conducted in these field trials. The results can be used for calculation of ECD and temperature profiles, which provide near real-time downhole data for monitoring and diagnostic applications. The measured pressure data also provide new insights about tracking of drilling microchips in the wellbore.
How Expandable Casing Patches Can Restore Casing Integrity and Enable the Sidetracking of an Old Well
Authors: Shahreyar Rehan , Kelly Mitchell , Albouy Charles , Saltel Benjamin , Le Pouezard Benjamin 
Published: February 2023

AbstractThis paper describes how an operator restored the casing integrity of a nonproducing well to resume offshore drilling operations by installing four 10¾-in. overlapping expandable steel patches.From 2020 to 2022, the operator scheduled a sidetrack drilling program, Māui A Crestal Infill (MACI), from the Māui A offshore platform, located in the Taranaki Basin of New Zealand. The operations included eight wells targeting the remaining unswept zones within the Māui A structure. During a reentry in a plugged and abandoned well, MA-03, a multifinger caliper log and a failed pressure test indicated a casing leak in the 10¾-in. intermediate casing. The log identified severe longitudinal casing wear with some fully penetrating holes. This lack of integrity prevented the scheduled operations from being performed.Several lost circulation material (LCM) and cement squeeze jobs attempted to seal off the leak but were unsuccessful. A service company proposed a mechanical repair solution to cover the long interval with four 13-m- (42.7-ft)-long customized, overlapping patches. Later, a second caliper was run to check if the cement squeeze jobs had reinforced the area for better patch support. Surprisingly, the zone appeared significantly more damaged, with a complete circumferential casing breach. Thus, the planned solution looked very challenging to implement.A video camera run, additional thinking, modeling, and cooperative engineering led to a complete redesign of the solution. The lengths and positions of the patches were changed, and one of the patches was assigned to serve as an inner reinforcement.The team assembled, deployed, and installed the patches in an accelerated mode. In 10 days, the casing integrity was fully restored, enabling the 8½-in. sidetrack hole to be drilled to total depth.This case is a typical example of how industry practices should evolve regarding the management of casing integrity issues. Remedial cement squeezes are often prioritized over mechanical options, even though mechanical options are now adjustable, much quicker to implement, and likely offer greater success rates.
World's First Advanced Dual ESP System Deployment for Harsh Environment
Authors: Aldossary Abdulrahman Theeb , Partadiwirya Rusam , Subijanto Riza Tjahyadi , Mahmoud Akram 
Published: February 2023

AbstractA Dual ESP system is a redundant ESP concept that provides backup ESP system to be put on stream immediately if the primary ESP fails, which minimizes workover ESP replacement requirements and cost. An enhanced Dual ESP system for a harsh environment is installed to prolong ESP run life. These harsh environment Dual ESP system are equipped with full Metal-to-Metal Motor Lead Extension as well as H2S Scavenger seal sections on both upper and lower pumps to enhance their durability. Moreover, auto-check valves are included in the system to enhance dual ESP daily operation and maintenance. This paper will share the new dual ESP system design for harsh environments, enhancements, and successful applications in offshore fields.Two identical, complete, and independent ESP systems are installed with standard Y-Tool (bypass system). All if which was achieved by installing the Metal-to-Metal Motor Lead Extension (MLE) Dual ESP application which acts as backup ESP system to be put on stream immediately after the primary ESP fails. Thus, avails the well potential and postpones the requirement of workover rig mobilization to replace failed ESP. Backup dual-ESP system extend overall ESP system run life in areas with limited rig availability.The cutting-edge technologies that were deployed in this completion include:Metal to Metal MLE on both lower and upper ESPs, which proved the increase in the run life compared to the standard MLE. Severe Service Seals (H2S Scavenger Seals), which protects the motor from corrosive subsurface elements. Dual Y-Tools to allow reservoir intervention below the ESP through bypass for logging, acid job and any Wireline / Coil Tubing jobs needed. Non-Return Valve (NRV) which facilitate auto switching between the upper and lower ESPs eliminating the costly offshore barge and wireline conventionally required to install isolation sleeves and blanking plugs. Dual penetration bore Aflas Packer which allows using two cable penetrators and has an Aflas material for sour applications.This paper will provide in-depth information about each of the cutting-edge technologies deployed in this completion along with the added technical value of utilization. It will further provide the estimated significant cost avoidance achieved in offshore ESP fields following the deployment of this completion.
Fracture Characterisation and Basement Reservoir Potential of Phra Wihan Formation in Southern Part of Uttaradit Province, Northern Thailand
Authors: Piewmoh Watcharapong , Kanjanapayont Pitsanupong 
Published: February 2023

AbstractThis research describes the characterization of fractures in the Mesozoic sandstones Phra Wihan Formation exposed at the southern part of Uttaradit province, Northern Thailand. Fracture characterization of outcrop analog is important to determine potential of subsurface reservoir. The methodology using field study and petrography analysis to determine the relationship of fractures and other structures such as bedding plane and fold geometry. In addition, microstructure analysis can be analoged to the potential of reservoir. The Phra Wihan Formation composed of thick quartz arenite sandstone laminated with mudstones. The structural architectures in study area are remarked by two open fracture sets with orthogonal relationship dominated in the fold limb. The first Set I, subdivided into Set Ia and Set Ib, developed in WNW-ESE direction perpendicular to the fold axial plane and parallel to the major compression stress. The second Set II, subdivided into Set IIa and Set IIb, developed in NNE-SSW direction parallel to the fold axial plane. These fractures imply to be associated with folding stage related to WNW-ESE compression stress during India-Eurasia collision.