bluuebunny/crossref_metadata_2025 huggingface dataset:
Successfully Installing ICD Screens and Hydraulic Packers without Washpipe Using Novel Check-Valve ICDS: Case Study Offshore Canada
Authors: Dikshit Ashutosh , Kumar Amrendra , Froom Bruce
Published: March 2021

Objective was to complete two ~16,000 ft MD offshore, openhole, horizontal wells with inflow control device (ICD) screens and hydraulic packers in acost-effective and risk-reduced manner. A major goal for the lower completion was to eliminate running washpipe for fluid circulation and intervention stringfor hydraulic packer setting to reduce rig time, equipment costs and operation/safety risks. A cost effective check-valve inflow control device (CV-ICD) screen solution, as described herein, was used on these two wells to achieve both of these purpose.

CV-ICD consists a nozzle with a 1) ceramic ball to seal against it's throat and 2) porous aluminum plate to retain the loose ball until injection pushes it against the throat. Extensive testing was performed under target conditions to ensure a 5,000psi differential pressure rating for setting open hole hydraulic packer.

Strict adherence to technical details helped transform the relatively simple concept of a ball-type, CV-ICD into a robust and reliable technology. The results of the extensive laboratory testing, as discussed herein, demonstrated: 1) HTHP functionality of the CV-ICD before/after exposure to wellbore fluids, 2) removal of the aluminum "cage" only after the ball is no longer required, and 3) acceptable flow performance of the ICDs with/without the loose ball present. Strict manufacturing and onsite QAQC procedures proved indispensable for success, especially given the challenging environment offshore.

Fluid circulation through the toe valve without washpipe was achieved while running the screen in wellbore. After reaching target depth (TD), the toe valve was closed there by allowing the string to be pressured up to set the hydraulic packers. The tubing pressure was successfully increased to ~5,000 psi against CV-ICDs to set the hydraulic packers. Overall, the completions were a success as discussed in more detail herein, along with valuable lessons learned.

The case studies presented herein demonstrated costs and risks associated with using a washpipe to deploy ICD screens to TD can be significantly reduced with a novel yet cost-effective CV-ICD solution. The integration of check ball with an ICD, while simple in concept, provide siginifcant value if the strict adherence to technical details, rigorous testing and diligent quality control are followed.
Study and Application of Pulse Hydraulic Fracturing for Tight Oil Reservoir
Authors: Xu Hongxing , Sun Hu , Wang Zuwen , Zhang Mian , Lan Jianping , Deng Binqi , Li Yanhong
Published: March 2021

Pulse hydraulic fracturing is a promising stimulation technology to enhance the effectively permeability of coal seams. The fundamental of pulse hydraulic fracturing is that fracturing fluids with a certain frequency are injected into coal, resulting in the rupture of coal and forming a well-distributed fracture network due to the pulse loading. Better effects of gas extraction using pulse hydraulic fracturing had been gotten compared with that of hydraulic fracturing. Accordingly, how to apply pulse hydraulic fracturing technology to improve the fracturing effect of tight and shale reservoirs is a question worth thinking about, although this is very challenging due to the totally different downhole operating conditions. In this paper, experimental apparatus for fatigue damage of quasi-triaxial rock under alternating loads was established. The maximum injection pressure is 50MPa, while the pulse pressure amplitude is greater than 5MPa, and the pulse frequency is adjustable from 0 to 50Hz. Rock failure experiments under pulsating load were carried out and the effects of different hydraulic pulse parameters and rock properties on rock damage were studied. Experimental results show that hydraulic pulse has different effects on rock compressive strength and fracture pressure of different properties. With the increase of hydraulic pulse frequency, the influence on rock compressive strength increases firstly and then decreases. With the increase of pulse pressure amplitude, the influence on rock strength increases. With the increase of hydraulic pulse processing time, the influence on rock fracture pressure increases firstly and then tends to stabilize. Hydraulic pulse has the greatest influence on the compressive strength and fracture pressure of He 8 reservoir, followed by Chang 8 and Chang 6 reservoir of Changqing Oilfield in China. Based on the experimental results, hydraulic pulse frequency is preferred to be about 18-20Hz, accordingly, a downhole hydraulic pulse generator is designed and manufactured. The indoor test results show that the generator performance meets the design requirements. Field tests of pulse hydraulic fracturing were carried out in 3 wells in Changqing tight oil reservoir. Encouraging results were obtained, the average construction pressure was reduced obviously and average daily production per well increased significantly compared to adjacent wells.
Experimental Investigation of CO2 Huff and Puff Process Based on Three-Dimensional Physical Models
Authors: Tang Xiang , Li Yiqiang , Yu Zhihao , Xu Miaomiao , Zhou Rui
Published: March 2021

As an important enhanced oil recovery method for tight reservoirs, CO2 huff and puff (HnP) is getting more attention in recent years. It is urgent to systematically study the characters of CO2 HnP. Due to the limitations of numerical simulation, it is more reliable and reasonable to study the development characteristics of CO2 HnP through experiments. The objective of this work is to conduct comprehensive experiments to clarify the characters and main mechanisms of CO2 HnP process based on the three-dimensional (3D) physical models.

A 3D physical experimental apparatus with circumstance of high temperature and high pressure has been developed, which is mainly used to support the models with a fixed confining pressure and temperature. Based on the similarity criterion of dimensionless conductivity, two different 3D physical models (30cm×30cm×3.5cm) with a horizontal well and fractures are made from outcrops to imitate the different reservoirs. Under these preconditions, some CO2 HnP experiments were conducted to investigate the development characteristics from the 3D physical models.Also,long core experiments were carried out to establish and verify the production prediction model, combined with expansion test, diffusion test and nuclear magnetic resonance test.

The experimental results show that the development process of CO2 HnP can be divided into four stages: CO2 backflow, Gas production with attached oil, High-speed oil production and Decay. The main mechanism of oil production in each stage is different. With the increase of the cycle number, the recovery factors of both models first increase and then decrease, while the oil/gas replacement rates may drop rapidly. The fractures have been proven to increase the oil recovery from 21.2% to 36.7% after ten rounds of CO2 HnP. Based on the analysis of expansion and molecular diffusion, a production prediction model was established, and the average error between the predicted results and the experimental results is 7.7%, which has good applicability and accuracy.

In this paper, some large-scale 3D physical model experiments with CO2 HnP for tight reservoir were elaborated. The development characteristics of CO2 HnP were analyzed, and a production prediction model was established. A lot of valuable experimental data and a better understanding on CO2 HnP process in tight reservoir have been obtained.
Inversion of Reservoir Parameters by Ultra-High Temperature and High Pressure CO2 Gas Reservoirs with Nuclear Logging
Authors: Zhang Hengrong , Xiao Lizhi , Wu Wensheng , Fu Xinyue , He Shenglin
Published: March 2021

The Yinggehai basin is located in the western part of the South China Sea, the burial depth of the Huangliu and Meishan formations in the target layer is close to 4000 meters, the formation temperature is close to 200 degrees Celsius, and the formation pressure is up to 100 MPa. The reservoir is characterized by low porosity-ultra-low permeability, heavy carbonate cement, complex CO2 content, this leads to complex neutron and density logging effects.

The solubility of CO2 Above CH4, the solubility change with temperature and pressure is different from CH4, which makes it difficult to identify the CO2 gas layer. In this paper, based on the difference in the physical characteristics of CO2 and CH4, the Boltzmann equation combined with MCNP software was used to simulate the neutron and density logging responses under different CO2 saturations. Environmental factors such as temperature and pressure, carbonate cement, mud content and pores were studied To measure the effect of logging response, the LM inversion method is used to jointly invert CO2 saturation of density and neutron logs.

The purpose of the inversion is to reduce the non-uniqueness of the evaluation of porosity and CO2 saturation. By introducing the Levenberg-Marquardt (LM) method, the neutron logging response equation of the porosity, argillaceous content, CO2, CH4 in the rock and the corresponding temperature and pressure is solved, and also the response equation of above parameters to density logging, where porosity and CO2 content are the key parameters, and the calculation results prove the effectiveness of the method by comparing the sampling data. The results show that the accuracy of the estimated CO2 saturation is increased by 10% compared with the conventional interpretation method, and the new simulation method improves the calculation speed several times compared to the MCNP software.

The joint inversion method has been successfully applied to field data, which has greatly improved the saturation evaluation results of traditional logging interpretation methods, can be extended to other fields of nuclear logging simulation and inversion.
Enzymatic Treatment of Phenolic Wastewater: Effects of Salinity and Biosurfactant Addition
Authors: Onaizi Sagheer A.
Published: March 2021

Water contaminated with phenols is produced from several oil and gas related industries. Although there are a number of treatment methods, enzymatic wastewater treatment is more attractive due to its sustainability, environmental-friendliness, and mild nature. A key limitation of this process, however, is the enzymatic deactivation (whether complete or partial) during the treatment process. This limitation might be addressed to a certain extent through the addition of biosurfactants to the reaction medium. Thus, the key aim of this study is to utilize laccase (an oxidoreductase enzyme from Trametes versicolor) to remove bisphenol A (BPA) from wastewaters in the presence of rhamnolipid biosurfactant. Since most wastewaters contain inorganic salts, the efficacy of enzymatic treatment of high saline wastewaters has been evaluated. The beneficial effect of the biosurfactant addition during the enzymatic treatment of highly saline phenolic wastewater has been also assessed. Additionally, the effect of increasing the biocatalyst and the phenolic pollutant concentrations have been also probed. The results showed that the BPA degradation rate increases with increasing the enzyme concentration. The extent of BPA removal also increased with increasing the biocatalyst concentration, approaching almost a complete removal at an enzyme concentration of 400 ppm. The BPA degradation rate also increased almost linearly with increasing its initial concentration; however, its removal extent showed the opposite trend. The addition of as low as 1 ppm rhamnolipid biosurfactant to the reaction medium increased both the BPA degradation rate and the removal extent relative to the biosurfactant-free wastewater samples. The addition of the biosurfactant to the reaction medium boosted the BPA degradation rate and the removal extent by 1.1- to 1.23-fold. The highest BPA degradation rate and removal enhancement (about 23% higher than those in the absence of the biosurfactant) was obtained for BPA-rhamnolipid mass ratio of 50:1. The presence of salt severely reduced the BPA degradation rate and removal. The addition of 20 mM NaCl resulted in about 1.7-fold drop in the BPA degradation rate and removal. The drop in the BPA degradation rate and removal reached more than 3.6-fold at 500 mM NaCl. The addition of 1 ppm rhamnolipid partially compensated the negative effect of salinity, providing relatively higher BPA degradation rate and removal at all examined salinity levels. The findings reported herein reveal the positive effect of biosurfactant addition to the enzymatic reaction medium and the need for the salt removal prior to subjecting the saline wastewaters to enzymatic treatment.
An Artificial Intelligence Neural Networks Driven Approach to Forecast Production in Unconventional Reservoirs – Comparative Analysis with Decline Curve
Authors: Khan Hassan , Louis Clifford
Published: March 2021

Subsurface engineers pivot on surveillance of reservoir performance for future production rates and plan the optimization strategies at earliest. There are some techniques preferred for unconventional reservoirs such as numerical simulation and decline curve analysis (DCA) for production forecasting, but the uncertainty of uneconomical well test data often occurs in unconventional resources. Moreover, reservoir engineers can also hit a tailback in optimizing and tuning the model. Further, for DCA this approach is only appropriate for well/reservoir that are under boundary dominant flow regime, whereas fracture dominant flow regime is often observed for a longer period in unconventional hydraulically fractured reservoirs. Therefore, to resolve this issue, oil & gas industry (O&G) can adopt AI (Artificial Intelligence) based Algorithms for production forecasting.

This paper presents a data-driven algorithm, known as Artificial Neural Networks (ANNs), along with time series forecasting that is a well-known statistical technique. Machine learning model trained by a past well performance data such as tubing head pressure (THP), flowing bottom-hole pressure can predict future production rates. This can be an efficient technique for subsurface engineers to monitor and optimize well performance. Time series neural networks were used for training the model at top and bottom node of the well with variating pressures in the past. After training and validation, the model predicted a target parameter that was gas rate. ANNs are inspired by biological neurons that are present in human brain, a powerful computing tool to make decisions after fueling itself with data. Moreover, prediction (t+1) nonlinear automated regression is preferred for accurate step ahead.

Production rates and constraints of unconventional reservoirs were used to train the model. In our results, the NN based model gave the co-efficient of determination (R2) of 0.996 that shows nearly an exact precision. Furthermore, the values generated from NN Model and Arp's decline curve calculations were plotted for validation and it turned out that ANN can accurately predict the parameters.

The Neural Network model is a novel approach for production forecasting, of unconventional reservoirs and help engineers in corporate decision making. This approach can mitigate the need of uneconomical well test operations and further provide confidence to production engineers in terms of data and result expectations.
Development of New Geopolymer-Based System for Challenging Well Conditions
Authors: Abd Rahman Siti Humairah , Medvedev Anatoly , Yakovlev Andrey , Sazali Yon Azwa , Jain Bipin , Hassan Norhasliza , Thompson Cameron
Published: March 2021

With the development of new oil formations and with the advent of new directions in the global energy sector, new requirements for materials for well construction appear. With the close attention to environmental footprint and unique properties, one of the promising materials for well cementing is geopolymers. Being a relatively new material, they are characterized by low carbon footprint, high acid resistance and attractive mechanical properties. This article is aimed at developing new geopolymer slurries for the oil industry, their characterization and field implementation analysis.

With the ultimate goal of developing a methodology for the analysis of raw materials and designing the geopolymer slurries, studies were carried out on various raw materials, including different types of fly ash. Based on the data obtained and rapid screening methods, an approach was developed to formulate a geopolymer composition recipe. Since not all cement additives directly work in geopolymers, special attention was paid to control the thickening time and fluid loss. The methods of XRD, XRF, ICP-MS, density, particle size distribution measurements as well as API methods of cement testing were used to understand the composition and structure of the materials obtained, their properties and design limitations. A special approach was applied to study the acid resistance of the materials obtained and to compare with conventional cements and slags.

Using one of the most common sources of aluminosilicate, fly ash, formulations with a density of 13.5 – 16.5 lbm/galUS were tested. A sensitivity analysis showed that the type of activator and its composition play a critical role both in the mechanical properties of the final product and in the solidification time and rheological properties of the product. The use of several samples of fly ash, significantly different in composition, made it possible to formulate the basic rules for the design of geopolymers for the oil industry. An analysis was also carried out on 10 different agents for filtration and 7 moderators to find a working formulation for the temperature range up to 100°C. The samples were systematically examined for changes in composition, strength, and acid resistance was previously measured.

Despite the emergence of examples of the use of geopolymers in the construction industry and examples of laboratory testing of geopolymers for the oil industry, to the best of our knowledge, there has been no evidence of pumping geopolymers into a well. Our work is an attempt to develop an adaptation of the construction industry knowledge to the unique high pressure, high temperature conditions of the oil and gas industry. The ambitions of this work go far beyond the laboratory tests and involve yard test experiments.
Application of Multi-Information Fusion Fracture Modelling Based on Neural Network in Carbonate Dual: Medium Reservoir
Authors: Dan Lingling , Shi Changlin , Wen Jiatao , Hu Yunting , Wei Li , Li Yunxiu , Zhang Jian , Tian Panpan
Published: March 2021

G oilfield in China is a dual medium oilfield dominated by carbonate reservoir, where faults and fractures are well developed. After G oilfield was put into production, water cut has rised quickly and oil production decreased rapidly. The heterogeneity of fracture development is very strong. Because of unclear understanding of the fracture distribution, oilfield development plan can not accurately identify risks and potentials accurately. As a result, production goals are not as expected. Due to limited core data and imaging logging data, conventional methods cannot characterize fracture information in this oilfield accurately and comprehensively. In order to solve the problems mentioned above, this paper makes full use of logging, geology, seismic and other data to carry out fine characterization of fracture with multi-information fusion fracture modeling based on neural network. Firstly, neural network technology is used to predict the fracture density curves of wells with conventional logging data. Secondly, combined the nonlinear fusion of multiple pre-stack seismic attributes including Tectonic Stress Field, P-Wave AVO and Seismic Discontinuity Detection based on neural network, the fracture density probability model is created to predict three-dimensional distribution of fractures. Thirdly, the fracture Intensity model is set up under the constraint of strict variation function analysis and fracture density probability model. Finally, fracture parameters are obtained according to core observation and imaging logging data, and the fracture network is established by geostatistics modeling method and coarsened equivalent into fracture property model. Blind well validation and dynamic validation are used to verify the validity of fracture model. Under the guidance of research results in this paper, the oilfield development plan is optimized and adjusted. It has also been proved that fracture characteristic of new wells is consistent with pre-drilling prediction result. Most areas with relatively high fracture development degree are corresponding to well groups with faster water cut rising rate. Against the backdrop of global oil economic downturn, fracture modeling technology studied in this paper provides strong technical guidance for oilfield development plan, therefore reducing oilfield development risks and maximizing economic benefits.
Digital Transformation of Production Allocation and Management for Oil and Gas Field
Authors: Zhao Han , Chen Guo , Zhang Su , Wang Fu Yong , Zhang Hua Yi , Li Meng , Xu Wen Qi , Wu Ting , Ren Jing Si
Published: March 2021

Output is the core index of oil and gas enterprises, and the management of output is very important to the operation of oil and gas enterprises. Each year, oil and gas companies will develop a production allocation plan according to well productivity. Under the guidance of the allocation plan, the annual production target would finally be achieved.

In the digital transforming stage of development and production management of oil and gas fields, the traditional offline manual production allocation can no longer meet the needs of delicacy management. For this reason, based on the development and production management platform, a system of production allocation and management was established and deployed in an international oil and gas company.

In this paper, through the information platform concept model, introduced the development and production management platform construction method. Based on the platform architecture, taking production allocation and management as an example, the system construction process is introduced from the aspects of business process splitting, system function design, data and software integration call, etc. Furthermore, through the integration of intelligent oil and gas project results based on the platform architecture, the integrated application of intelligent workflow to core business activities in the production allocation and management process is realized.

The platform has been fully applied by a large natural gas production company. Through this platform, a management mode with "business standardization, process standardization, and execution standardization" was adopted to realize the comprehensive transformation of production allocation and management from the traditional mode to the digital one. The application of the platform shows that: the process of production allocation and management optimized in process-driven way is traceable and can form a business closed loop; through process reorganization and integrated application, the efficient business collaboration across specialities and departments has been achieved, improving the scientific decision-making ability and the level of business management;
Assurance and Verification of Safety Critical Elements in Asset Management
Authors: Kamal Girish
Published: March 2021

Safety Critical Elements (SCEs) are the equipment and systems that provide the foundation of risk management associated with Major Accident Hazards (MAHs). A SCE is classified as an equipment, structure or system whose failure could cause or contribute to a major accident, or the purpose of which is to prevent or limit the effect of a major accident.

Once the SCE has been ascertained, it is essential to describe its critical function in terms of a Performance Standard. Based on the Performance Standard, assurance tasks can be stated in the maintenance system to ensure that the required performance is confirmed. By analyzing the data in the maintenance system, confidence can be gained that all the SCEs required to manage Major Accidents and Environmental Hazards are functioning correctly. Alternatively, corrective actions can be taken to reinstate the integrity of the systems if shortcomings are identified.

This paper shall detail out how the MAH and SCE Management process is initiated to follow the best industry practices in the identification and integrity management of major accident hazards as well as safety critical equipment. The tutorial shall describe in detail the following important stages:Identification of Major Accident HazardsIdentification of Safety Critical Equipment, involved in managing Major Accident HazardsDefine Performance Standards for these Safety Critical EquipmentExecution of the Assurance processes that maintain or ensure the continued suitability of the SCE Equipment, and that these are meeting the Performance StandardsVerification that all stages have been undertaken, any deviations being managed and thus that Major Accident Hazards are being controlled.Analyze and Improve

Through the diligent application of these stages, it is possible to meet the requirements for MAH and SCE Management process giving a better understanding and control of risks in the industry.
Study on Nanoparticle Stabilized Emulsions for Chemical Flooding Enhanced Oil Recovery
Authors: Zhu Youyi , Yu Peng , Fan Jian
Published: March 2021

Chemical flooding is one of enhanced oil recovery (EOR) methods. The primary mechanism of EOR of chemical flooding is interfacial tension reduction, mobility ratio improvement and wettability changes. Recent studies showed that enhancing emulsification performance was beneficial to improve oil displacement efficiency. The formation of Pickering emulsion by nanoparticles could greatly improve the emulsifying performance. Using nanoparticles stabilized emulsions for chemical EOR application is a novel method.

In this study, six different types of nanoparticles were selected, including hydrophilic nano silica, modified nano silica, carbon nanotubes and bentonite, etc. The nanoparticle combine with petroleum sulfonate could form a stable emulsion. Particle wettability were measured by using contact angle measurement (OCA20). Emulsifying intensity index was measured for different nanoparticle-stabilized emulsions. The mechanisms of nanoparticle-stabilized emulsions and relationship between emulsion stability have been investigated. The influence of dispersant on nanoparticle-stabilized emulsions also has been investigated.

Nanoparticles mainly play a role in improving the stability of emulsions while surfactant play a major role in enhancing the emulsifying dispersion. The wettability of solid particles was one of the most important factors that affects the stability of emulsions. Partial hydrophobic nanoparticles were much easier to form stable emulsions than hydrophilic nanoparticles. Nanoparticles could form a three-dimensional network structure, thereby the stability of the emulsion was improved. Use of surfactant to disperse nanoparticles could further improve the emulsion stability. Finally, three nanoparticles stabilized emulsion formulations were developed for chemical flooding EOR.

Nanoparticle-stabilized emulsions could improve oil displacement efficiency in chemical combination flooding. This research was used to optimize chemical combination flooding formulation and has a guidance function for application of nanoparticles in chemical flooding EOR.
Assessing the Impact of Shallow Gas Hydrate Dissociation on Structural Integrity in Deepwater Wells
Authors: Suryanarayana P. V. , Bogdanovic Miodrag , Thavaras Pathy Kuhanesapathy , Paimin M. Razali
Published: March 2021

Shallow gas hydrate zones are present in some deepwater fields. During production, the shallow hydrates may dissociate due to heat-up of the near wellbore formation, which can extend radially to several meters from the wellbore. This can compromise structural integrity of the well (particularly structural strings), cause subsidence, and impact subsea equipment installations. This problem is well known, and has been addressed in the literature. An enthalpy-based transient thermal simulation is required to determine the dissociation front. Further, post-dissociation formation mechanics and well integrity assessment are complex, requiring numerical approaches such as Finite Element Analyses. In this paper, we present an approach that allows a preliminary assessment of the severity of the impact of dissociation on well integrity, so that a more complex assessment may be undertaken only for severe situations. The main objectives of the preliminary assessment are: to model hydrate dissociation front and the radial extent of dissociation as a function of depth; evaluate response of formation to this dissociation; analyze mechanical response of the well to the modified mechanical properties within dissociated zone; and confirm well integrity. The paper describes the approach, and introduces two thermal metrics to assess the likely severity of the integrity impact of hydrate dissociation. Using these metrics, the need for a more detailed analysis can be determined. Further, load analysis and integrity checks of the structural strings and the wellhead that can be performed as part of the preliminary assessment are discussed. An illustrative example is used to demonstrate the approach.
Integrated Gas Source Analysis for Wells with Sustained Casing Pressure: A Case Study from Sour Gas Fields in Sichuan Basin, China
Authors: Su San , Vo Minh , Jia Changqing , Yuan Jianbo , Zhang Junliang , Zhang Qiang
Published: March 2021

Sustained casing pressures are observed in many gas-field wells in Sichuan Basin. The presence of corrosive sour gas i.e. H2S and/or CO2 in the annulus, coupling with the none corrosion-resistant alloy (CRA) casing materials, may damage the casing and lead to loss of containment, which could be a disaster to the asset, local communities, and the environment. It is thus of significance to identify the gas source for the wells with sustainable casing pressure.

Several wells in the study area were identified as risky wells with an initial risk screening exercise. The further determination of gas source, either sweet gas in the shallow formation or sour gas in the deep formation, would have a big impact on the risk levels and subsequent mitigation plans. An integrated forensic study was conducted to investigate the gas source, including annulus gas composition analysis, isotope fingerprinting, casing pressure profile construction and analysis, casing pressure bleed-off and build-up operations, cement quality evaluation, temperature and noise logging analysis, etc.

In this paper, the integration of various tools and data enabled a quality diagnosis of the gas source for two risky wells. It is believed the most likely gas source for the first well is from the shallow sweet gas formation. The risk was then revised down to Low-Medium, and the well was temporarily plugged and abandoned (P&A) for future use. For the second well, the gas source is confirmed from the deep sour gas formation, and thus the risk is relatively high. A permanent P&A program was performed, and both the sour and sweet gas layers were successfully isolated per the standard barrier requirement to protect community and environment.

In conclusion, most of the subsurface measurements have limitations and thus result in the imperfect data. The key to solving the subsurface puzzle is to consolidate all the perceptions together after reviewing the problem from different angles. The integration of multiple types of data in this study, including geological and engineering data, static and dynamic measurements, etc., allows a mostly likely interpretation of gas source to support the key operations decision. The results from integrated data analysis have helped improve the risk assessment, guide the development of risk mitigation plans and operations procedures to eliminate and/or reduce the risk of these wells and secure the subsurface integrity.
Pore Pressure Estimation by Using Machine Learning Model
Authors: Booncharoen Pichita , Rinsiri Thananya , Paiboon Pakawat , Karnbanjob Supaporn , Ackagosol Sonchawan , Chaiwan Prateep , Sapsomboon Ouraiwan
Published: March 2021

In the past few years, over hundreds of wells were drilled in Gulf of Thailand, had faced with the depletion and lost circulation issues resulted from a lack of pressure data. A prior research of reservoir depletion pressure (Fangming, 2009) in oil field, China was obtained from multivariate statistic and regression by using density and neutron porosity log curves in logging-while-drilling data. However, the relative errors are 7.5% from the actual formation pressure. Thus, there are several latent variables in the model like drilling parameters (Rehm, 1971) which part of formation pressure. From 2018 initiative model in Satun-Funan, the classification model was obtained by using mud gas, porosity, water saturation, net sand thickness, net-hydrocarbon-pore thickness and neutron-density separation. However, the limitation is drilling parameters could not account by classifier, and accurate only original pressure category. So, this study has expanded scope to include other reservoir properties and drilling parameters then applied with machine learning on offset well dataset by using three regressors such quantile, ridge and XGBoost regressors. The pore pressure estimation model aims to improve efficiency for making decision in execution phase, increasing confidence in perforation strategy. The model parameters, pay thickness, porosity, water saturation, original pressure from local pressure profile and total gas show are accounted into this model. As of regressor assumption, some facts are conducted to logarithm and perform 2nd polynomial feature for model flexibility. There are three steps for building model such as data manipulation, analysis and deployment. Two purposes of pressure prediction impact algorithm selection, for operational phase, quantile regressor is implemented to provide conservative prediction while Ridge or XGBoost regressors are alternatives for perforation strategy, provide mid case result of pressure prediction. Overall model performance was measured using root mean square error (RMSE) on train & test dataset which show approximately 1.2 and 1.5 ppg range of accuracy respectively from total 12 drilling projects in Pattani basin. Overall model fitting is within reasonable range of generalization capacity to apply with unknown data point (test set). The future model will continue to improve accuracy and manage imbalanced dataset between original pressure and depleted sands.
Smart Facility Advanced Separator
Authors: Watcharasing Sunisa , Lamsunthia Surachai , Phuphuak Yupin , Malatip Atipong , Pratumwal Yotsakorn , Kiattikomol Prapoj
Published: March 2021

The objective of this work was to develop the prototype unit of Advanced Production Separator (APS) for simultaneous removal of sand, out from production separator. APS unit was fabricated with size Diameter × Length: 1 × 2 m. System controlling of rotational blades impellers was installed at the bottom section of separator, to prevent sand accumulation at bottom of separator while on-service. This facility will help in preventing of sand accumulation in the separator, leading to minimize period of separator downtime during annual maintenance period, and allowing more working volume for open fluid reservoir to gas-oil phase production separator. Moreover, this will minimize working period for worker going inside the separator for sand clean-out, as a concern of working in the confine space.

The optimum conditions for separation of sand and crude oil will be examined, with Computational Fluid Dynamics (CFD) model simulation to observe hydrodynamic flow, relating the experimental conditions. The effects of size of 1) Imperller shapes (model A, B, and C), and 2) Rotational speed of impellers (0, 50, 100, 150, and 200 rpm) were investigated to determine the optimal conditions for APS system.

In this work, experimental test run result were compared with CFD simulation result. The optimum conditions for prototype APS unit (800 Litres capacity) is Fan C impeller shape for 5 items, and rotation speed for 150 rpm. This result shows the percentage of sand removal reaching to about 70%. The highest amount of sand in water outlet was found at this optimal condition, corresponding with the small part of sand dune at the bottom of the separator after impellers were driving sand to the outlet channel. From the test run, it was found that experimental results, and CFD simulation are consistent. CFD simulation result can be applied as a first screening to forecast sand removal pattern.

This research illustrate the alternative novel solution for solving sand production accumulation problem in production separator, by instantly clear sand out while crude oil operation was on-going. In the future phase, CFD simulation will be further used as a first step for predicting result before separator scale-up. Separator will be experimented with 4-phases (oil, water, gas, and sand), and further expand for 4X of the original size to see an effect of scale-up. Aim to unlock high potential field, by reducing downtime of the separation during sand cleaning, and providing more working volume of separator after sand was removed out from self-cleaning separator.
Full Wavefield Redatuming: Accurate Velocity Modelling for Imaging Beneath Complex Overburden
Authors: Dzulkefli Farah Syazana , Xin Kefeng , Ghazali Ahmad Riza , Qiang Guo , Alkhalifah Tariq
Published: March 2021

Salt is known for having a generally low density and higher velocity compared with the surrounding rock layers which causes the energy to scatter once the seismic wavefield hits the salt body and relatively less energy is transmitted through the salt to the deeper subsurface. As a result, most of imaging approaches are unable to image the base of the salt and the reservoir below the salt. Even the velocity model building such as FWI often fails to illuminate the deeper parts of salt area. In this paper, we show that Full Wavefield Redatuming (FWR) is used to retrieved and enhance the seismic data below the salt area, leading to a better seismic image quality and allowing us to focus on updating the velocity in target area below the salt. However, this redatuming approach requires a good overburden velocity model to retrieved good redatumed data. Thus, by using synthetic SEAM model, our objective is to study on the accuracy of the overburden velocity model required for imaging beneath complex overburden. The results show that the kinematic components of wave propagation are preserved through redatuming even with heavily smoothed overburden velocity model.
Qualification and Application of All Electric and Topside Less Subsea Multiphase Pump Technology in Subsea Factory Mission to Minimise the Life Cycle Cost
Authors: Ilangovan Karthik , Dindi Mazlan , Fuglesang Alexander , Van Der Rest Bastiaen
Published: March 2021

In recent years, various operating companies have been working on the processes of "Simplification, Standardization, Automation, Digitalization, and Optimization in several elements". To achieve this, there are tremendous subsea technology developments going on all over the world in many areas such as; design in terms of size and weight, improvement in reliability, advanced materials, flow assurance, digital tools, real time condition monitoring and control, installation and operation.

The development of Subsea technology continues to be an important part of subsea field development projects to reduce the life cycle costs, increase recovery, provide solution to long tieback problems and challenges. PETRONAS ("the Company") is pursuing an Upstream Life Cycle Cost (CAPEX/OPEX) reduction approach under the Facilities of Future (FOF) program and mission called "Subsea Factory". The FOF target is to reduce Upstream life cycle cost by 40% starting from 2025 and Subsea Factory is one of the enablers to contribute to the reduction. There are four primary technologies focused on Subsea Factory: Subsea Separation, Subsea Multiphase Pump, Water Injection and Subsea Storage. The Subsea Multiphase Pump is one of the prioritized technologies for Subsea Factory to contribute to a 40% reduction. Subsea multiphase pump technology has great potential to reduce the CAPEX/OPEX and increase oil recovery, but due to the high equipment cost, huge topside space requirement, reliability and operating issues become very challenging and limit its application to operating companies.

The Company collaborates with FASTsubsea AS on a Joint Industry Project to develop and qualify "the World first All Electric & Topside-less Subsea Multiphase Pump Technology". The uniqueness about this technology compared to commonly installed subsea pump is that it requires much less topside space as there is no need for variable speed drives or barrier fluid hydraulic power units.

This paper describes the qualification and application of All-electric & Topside-less subsea multiphase pump technology in the Company - Subsea Factory mission, including: pain point with conventional subsea multiphase pumpthe Joint Industrial Project initiative with respect to technology development to pilot test to maturityimplementation of this technology and value creation in upcoming field development projectthe case study and potential of this technology for the Company future field development project
Material Selection and Corrosion Rate Analysis for CO2 Injection Well: A Case Study of K1 Field CO2 Sequestration Project
Authors: Abu Bakar Mohd Azuan , Wan Mohamad Wan Amni , Moh Wahi M Wahidullah , Ebining Amir Muhammad Syafeeq
Published: March 2021

The CO2 sequestration project is becoming increasingly attractive due to tax exemption benefits and as an initiative to reduce the global warming effect (D'Alesio, P., Poloni, R., Valente, P., & Magarini, P. A.2010). One of the major challenges in CO2 sequestration project is to ensure that the injection well integrity is intact throughout the well operating life. CO2 gas leakage to the surface or sea is unacceptable. Therefore, the considerations of using exotic/premium tubing materials are usually considered as the base case for continuous long-term operations (Baklid, A., Korbol, R., & Owren, G.1996).

Typical materials used for CO2 injector wells are either Corrosion Resistant Alloy (CRA) or epoxy lined tubulars. The most widely adopted CRA material is 25 Cr (L. Smith, M.A. Billingham, C.-H. Lee, D. Milanovic, 2011). Selection of 25 Cr material is considered as conservative and may well be overdesigning. The main drawback is the high well cost associated with the application of 25 Cr tubing. Meanwhile, alternative materials such as epoxy lined tubulars are exposed to high temperature and pressure blistering effects and prone to mechanical damage caused by wireline activities, hauling, running, and pulling off the tubing (Newton, L. E., & McClay, R. A, 1977).

Application of materials other than 25 Cr for CO2 injector wells, such as 22 Cr, Super 17 Cr, Super 15 Cr, Super 13 Cr, 13 Cr and carbon steel are uncommon but may be fit for purpose. Detailed studies using analytical method and physical tests are required to further qualify these materials for application in CO2 injector wells. These studies should cover all possible conditions throughout the well life such as injection, shut-in, flowback and by considering surface and bottom hole conditions which may contribute to increase in the corrosion rates for different types of materials. Other tests warranted before selecting the suitable material for field application include physical coupon, Sulfide Stress Cracking (SSC) and Stress Corrosion Cracking (SCC) tests.

This paper describes the material selection methodology and corrosion studies performed in the K1 field CO2 sequestration project using the other materials mentioned above as an effort to optimize well costs and improve overall project economics without jeopardizing the CO2 injector well integrity.
Experimental Study on Water Imbibition Law of Longmaxi Formation Shale in the Sichuan Basin
Authors: Tao Liang , Zhao Yuhang , Zhang Xiaozhuo , Wang Yanxing , Feng Hongbo , Cao Yujie , Zhao Zhihong
Published: March 2021

Water imbibition is a key factor affecting the flowback system of shale gas wells after volume fracturing. This paper took shale samples from the Longmaxi formation (LF) in the Sichuan Basin as subjects, the experiments of shale water imbibition under different influencing factors were carried out. The water imbibition law was analyzed, and the shale water imbibition capacity was quantitatively characterized, the question if shut-down is necessary after volume fracturing of wells in shale gas reservoir has been answered objectively. The experimental results show that: according to imbibition saturation, the shale water imbibition can be divided into 3 periods, imbibition diffusion, imbibition transition and imbibition balance periods. Among them, the imbibition diffusion period is the main period for imbibition capacity rise. The shale sample with horizontal bedding had much larger imbibition capacity than the sample with vertical bedding. The initial micro-fractures provide percolation pathways for shale imbibition, making flow resistance drop and imbibition capacity increase rapidly. Imbibition capacities of the shale samples to different types of fluids in descending order were: deionized water, slick water, 2% KCl solution and kerosene. The micro-fracfures induced by shale hydration were mainly lamellation, with obvious directionality. Shale hydration can improve the fracturing effect of reservoir, resulting in the increase of porosity of 0.08-1.04 times and increase of permeability of 2.3-173.6 times. The study results can provide scientific basis for the optimization of flowback system of shale gas wells.