bluuebunny/crossref_metadata_2025_split huggingface dataset:
Hybrid Pipeline Fit for Purpose for Multiphase Gas and Condensate Transportation
Authors: Mukhtar Nur Izyan , A Razak M Hasbi , Jamil Zurina 
Published: March 2022

Abstract
Corrosion and materials degradation factors during normal and abnormal operating conditions are among the essential criterion in evaluating materials suitability for an offshore pipeline transporting treated gas and condensate with contaminants i.e. CO2, Materials resistant to wet H2S damage in accordance with ISO 15156 requirements and mercury. A thorough study was conducted to ascertain the pipeline section that will be exposed to sour service conditions due to substantial Materials resistant to wet H2S damage in accordance with ISO 15156 requirements level along the pipeline during certain transient scenarios. The study was conducted in view of fit-for-purpose solution and CAPEX optimization initiatives for the project. During certain transient scenarios, there is potential exposure to substantial H2S level under wet conditions for a certain pipeline length which increases materials susceptibility to wet H2S damage such as Hydrogen Induced Cracking (HIC)/Stepwise Cracking (SWC) and Sulfide Stress Cracking (SSC). Flow assurance modeling with compositional tracking module was used to determine the level of H2S along the pipeline where few potential scenarios leading to sour conditions were considered. Risk assessments were also conducted to ascertain the impact and mitigations for the scenarios. Based on studies, exposure to sour service conditions is expected at a partial length of the pipeline as the H2S level exceeds the sour service limit during specific transient scenarios. Specific mitigation measures involving chemical injection, process control and safeguarding and operating procedures were outlined. The study successfully demonstrated an optimized materials selection approach for the pipeline.
Determining Long-Term Fate of a CO2 Sequestration Project Utilizing Rigorous Well Integrity Risk Assessment Strategy
Authors: Patil Parimal Arjun , Hamimi Asyraf M , Bakar M Azuan B Abu , Das Debasis Priyadarshan , Tiwari Pankaj Kumar , Chidambaram Prasanna , B A Jalil M Azran 
Published: March 2022

Abstract
Depleted hydrocarbon reservoirs are considered inherently safe for carbon sequestration, but high well density penetrating the CO2 storage reservoir could compromise the containment performance in a carbon, capture & sequestration (CCS) project. Based on the available well data, it is crucial to understand the age of the well, materials used for wellbore construction, cement quality, barriers performance, and well integrity. A risk management methodology can be incorporated to evaluate primary and secondary barriers in existing plugged and abandoned (P&A) and development wells to ensure long-term fate of CO2 sequestration project.
Existing P&A wells and development wells in a depleted field were drilled 3–5 decades ago. The wellbore construction utilized non-corrosive resistant materials. Health of all wells that ever penetrated the CO2 storage reservoir need to be analyzed from long term perspective of storing CO2. Throughout the lifespan of wells, subsurface barriers should maintain hydraulic isolation to prevent leakage happening from subsurface to environment of reservoir fluids and injected CO2. Deterioration of strength of wellbore construction material due to corrosion, induced by downhole pressure and temperature conditions, should be considered. This study investigated 3 exploration and 21 development wells. Risk register was developed for each well describing causes and CO2 leakage risks, impacts and consequences. Metrics were defined for parameters such as well age, well head materials, wellhead functional test and leak test, sustained casing pressures for risk determination. Wells were risk rated individually based on the assessment. Wells with low risk can be utilized for well conversion. While for high-risk wells, an opportunity risk matrix was developed to mitigate risks in all the wells.
This study evaluates the well integrity and CO2 leakage risk along the wells that penetrated the CO2 storage reservoir. The improved rigorous risk assessment exercise evaluates well barrier failure causes and impacts along with estimating the risk number per well. The well risk assessment score calculated was between 9.24 and 13.35 for 21 development wells. Out of these 21 wells, 4 wells with risk score &lt;10 can be utilized for wells conversion. Specific barrier restoration process by additional scope of work such as lower completion removal including packer milling, intermediate casing removal, or installation of downhole permanent barriers with remedial cement is discussed for designing the well abandonment process to minimize leak potential of high-risk wells for ensuring long-term containment security.
Improved rigorous well integrity risk assessment for CO2 storage field is decisive for any CCS project economics that utilizes barrier identification process and remedial actions.
Reduction of Residual Oil in Oil-Wet Carbonate Formations by Application of Hybrid Smart Water/Silica Nanofluid Enhanced Oil Recovery Method
Authors: Mahmoudpour Maziar , Pourafshary Peyman , Moradi Babak , Rasaei Mohammad Reza , Hassani Kamran 
Published: March 2022

Abstract
Smart water flooding has recently been considered as an attractive EOR method due to its lack of expensive chemicals. Alterations in oil/brine/rock interactions in porous media, such as wettability by smart water, affects oil recovery. Different mechanisms, such as wettability alteration, changes in the viscosity, changes in the interfacial tension and control of small particle migration, make nanofluid injection an effective method. In this study, the injection of a combination of smart water and silica nanoparticles is investigated for EOR. Different characterization measurements, such as contact angle, interfacial tension, zeta potential, X-ray diffraction, viscosity and core flooding are performed to investigate the effect of the developed method on oil recovery and the mechanisms changing sweep efficiency. Our results show that the highest oil recovery is achieved by the injection of smart water with a high concentration of sulfate ions combined with silica nanoparticles with a concentration of 0.1 wt.%. The addition of silica nanoparticles to smart water improves the wettability alteration mechanism, as well as increasing the fluid viscosity and affecting the sweep efficiency. Therefore, the application of the developed hybrid method exhibits distinct advantages compared to stand-alone smart water flooding.
Research and Application of Comprehensive Adjustment Technology for Offshore Polymer Flooding Oilfield
Authors: Kang Xiaodong , Zhang Jian , Li Peng , Zeng Yang 
Published: March 2022

Abstract
During the implementation of polymer flooding, high injection pressure and water cut return occur in the later stage. The early polymer flooding in offshore oilfields is more sensitive to the change of injection and production rate, so it is necessary to explore a new early polymer injection development mode suitable for offshore oilfields. By considering the impact factors of early polymer flooding development in offshore oilfields, such as large well spacing, thick oil layer, early polymer injection timing, limited platform life and space, the "pan type" development mode of polymer flooding water cut in offshore oilfields is established based on experimental research and numerical simulation and achieved the polymer flooding overall infill, polymer/surface binary flooding, unstable polymer flooding technology which has been applied in 3 oilfields in Bohai bay, providing support for the polymer flooding technology development in offshore oil fields in China.
Corrosion Management of Wet Gas Sour Gas Carbon Steel Pipeline with Corrosion Inhibitor and Mono-Ethylene-Glycol in NACE Region 3
Authors: Leow Chun Ho , Ong Hock Guan , Lee Rachel , Khoo Cheng Ai 
Published: March 2022

Abstract
This paper will present corrosion management of a wet sour gas carbon steel export pipeline using continuous and batch corrosion inhibitors with mono-ethlene-glycol (MEG) as hydrate mitigation strategy in NACE MR 0175/ ISO 15156 region 3 (severe sour). The wet sour gas carbon steel export pipeline corrosion management via continuous CI and batch inhibitors with closed loop MEG regeneration system is rare worldwide. This is especially challenging when the case study may potentially be the longest wet sour gas, large diameter carbon steel pipeline (approximately 207km × 32 inch) in the world thus far. Pipeline corrosion management and hydrate management aspects when being reviewed holistically, it could provide significant cost savings yet safeguarding the overall technical integrity of the pipeline. The overall corrosion management leverages on Shell's many years of JIP and operating experience in sour service including the pipeline material specification, corrosion management, inspection, and maintenance philosophy. Reliable correlation between reservoir properties and uncertainties severe sour service, flow assurance, chemical behavirous, operating experiences etc were considered to best represent the operating envelope for this wet sour gas carbon steel pipeline. This includes the testing and selection of continuous CI and batch inhibitor, corrosion monitoring, operational pigging, maintenance, and inspection requirements throughout the field life.
Encapsulating Complex Carbonate Facie Heterogeneity into Static Reservoir Model through Seismic-Based Characterization, Lang-Lebah Field, Central Luconia, Offshore Sarawak
Authors: Suwannasri Krongrath , Yaw Peng Cheong , Asawachaisujja Sirada , Uttareun Ratchadaporn , Limpornpipat Orapan , Suphawajruksakul Apichart , Chongrueanglap Pongsit 
Published: March 2022

Abstract
Capturing the reservoir heterogeneity is crucial for optimizing field development. Lang-Lebah field is a Miocene carbonate platform with approximately 5 sq.km. in size and over 1 km in height with a high degree of heterogeneity in both vertical and horizontal directions. In this study, we conducted a seismic-based characterization to capture reservoir heterogeneity and then ran sequential gaussian simulation with a data from wells to build a static model for field development purpose.
The method mainly comprises of four steps. The first step is to establish a relationship between reservoir properties (such as facie and porosity) to elastic properties (such as P- and S-wave impedances) to build conditional probability. The second step is running pre-stack inversion to derive P- and S-wave impedances as inputs for the third step. The posterior probability of each facie is determined through Bayesian classification using inverted impedances and the derived conditional probability as inputs. The last step is employing sequential gaussian simulation to build a static model using derived posterior probability of each facie and porosity cube.
The static model encapsulates heterogeneity in terms of carbonate facie and reservoir properties. The observed heterogeneity is highly consistent with the understanding of geological model of this carbonate platform. The result shows lateral heterogeneity in each zone of high energy facies (such as reef margin) at the windward flank of the platform and low energy facies (such as lake) at platform interior. Thus, this result was elaborated for geological concept beyond the using well data alone. The result also shows a vertical succession from different carbonate reservoir deposit regarding to accommodation as carbonate build-out to a typical carbonate platform build-up continue to carbonate build-in. In addition, flooding event or surfaces, which is part of reservoir barrier, was also identified and included in this static model.
The details of this successful novel study lay a fundamental work process for battling the challenge of gigantic carbonate characterization for field development. Because of this sophisticated model, we can properly plan the sequence of production and producing well targeting based on the derived reservoir heterogeneity resulting in enabling several Tscf of reserves and minimizing development costs.
An Investigation on the Influence of Structural Damage on Eigenvalue Characteristics and Reserve Strength Ratio of Onshore Lattice Steel Structures
Authors: Muhaimin Wan Farra Ayesha Binti Wan , Liew Mohd Shahir , Zawawi Noor Amila Binti Wan Abdullah , Shawn Lim Eu , Sheikh Anas Khaled Al , Salim Siddique Mohd Yatim Bin , Danyaro Kamaluddeen Usman 
Published: March 2022

Abstract
In the study of structural strength, the reserve strength ratio provides a measure of the ultimate strength capacity of a structure. Under actual site conditions, the reserve strength ratio may vary from its design values with loss of stiffness and changes in structural integrity. Changes in the vibrational response of a structure due to loss of stiffness is observed as a form of structural health monitoring (SHM). The aim of this study is to investigate the relationship and sensitivity of the reserve strength ratio of a structure to changes in natural frequency due to damage occurrences as a measure of global structural integrity. The reduction of stiffness is simulated by the sequential removal of members according loading path within the model. To obtain the values used for comparison, a non-linear pushover analysis and eigenvalue analysis is utilized to obtain the Reserve Strength Ratio (RSR) and eigenvalue for intact as well as simulated progressive damage conditions. The pattern recognized from the analysis performed indicated that as the reserve strength ratio (RSR) is reduced with reduction of stiffness by the removal of primary and secondary members, the eigenvalues for each respective model showing similar reductions.
Integrated Well Test Interpretation Approach for Complicated Carbonate Reservoirs: A Field Case
Authors: Liu Yongjie , Sun Zhaobo , Yang Renfeng 
Published: March 2022

Abstract
A oilfield, located in Iraq, is a large multi-layer oil field dominated by carbonate reservoirs of cretaceous Mishrif formation and Tertiary Asmari Formation. A oilfield is located in the transition zone between Zagros orogenic belt and the eastern edge of Arabian platform, mainly in the low-angle fold belt of Zagros structure. Due to the influence of the Zagros orogeny, the fault system of the oilfield is developed, especially the Asmari formation A. It is a complex carbonate reservoir composed of dolomite, limestone and sandstone. The plane and vertical heterogeneity are very strong. The development of micro-fractures is verified by core data, logging data and dynamic analysis. And the multiplicity of well test interpretation is obvious.
The core, thin section, imaging logging and well test data (Fig.1) of A oilfield all show that fractures are developed in Asmari formation, and the production performance shows that the existence of fractures improves the production of oil wells. However, due to the serious breakthrough of edge water and secondary bottom water, the water cut of the oilfield rises rapidly, leading to the difficulty in ensuring the development effect of the oilfield. Moreover, the fracture scale in the study area is too small to characterize the parameters, the plane distribution of fractures is different and its distribution law is difficult to predict accurately, which has also become the key to restrict the efficient development of oil fields. As carbonate reservoir has developed fractures and strong heterogeneity, its pore structure is more complex than sandstone reservoir, and the uncertainty of parameter interpretation is higher. Therefore, how to evaluate and obtain the reservoir parameters of A oilfield has always been a great concern.
In general, logging, core analysis and pressure transient analysis (PTA) are used to evaluate the reservoir parameters of carbonate rocks. However, core and logging analysis can be used to get static parameters in the range of centimeter to meter, while PTA can obtain static and dynamic parameters in the range of hundreds of meters to several kilometers, such as skin coefficient, boundary conditions, permeability and cross flow coefficient. Therefore, the PTA results are more practical.
Hydraulic Fracturing to Investigate Impact of Fracturing Medium, Bedding Angle and Perforation Length on Fracture Growth in Low and High Brittle Shale
Authors: Khan Javed Akbar , Padmanabhan Eswaran , Ul-Haq Izhar 
Published: March 2022

Abstract
Advancements in the technique for early estimation of the hydraulic fracturing potential of fracturing fluid in different shale formations are needed to successfully stimulate reservoir volume and recover the trap hydrocarbons. The determination of fracture initiation and propagation in shale remains unclear, particularly with regard to the choice of type of fracturing fluid during fracturing operation at high confinement. Hydraulic fracturing with supercritical carbon dioxide (SC CO2) and SC CO2 foam are an encouraging technique to overcome significant use of water in shale gas production. Our study was carried out to explore the fracture propagation and fracture initiation pressure under high confinement stress. The hydraulic fracturing experiments are performed to study fracture propagation in the black shale of three different fields to generalize the scope of work using low, medium and high brittle shale: Eagle Ford, Wolfcamp and Mancos. Three different fracturing fluids were selected for fracturing tests: SC CO2, SC CO2 foam and slick water to investigate the impact of low, medium and high viscous fluids. We evaluated the fracture pressure curve, breakdown pressure (fracture initiation pressure), fracture network variation and the impact of bedding angle, perforation length, injection mediums and formation variations on fracture morphology. During hydraulic fracturing with slick water a consistent rise in the injection pressure is recorded whereas sudden fluctuations are recoded with the injection of SC CO2. With the injection of SC CO2 foam, a sudden decrease in injection pressure appears due to imbibition of SC CO2 foam in the pores matrix. Moreover, fracture initiation pressures in shale rocks varied by changing bedding angle and perforation length. Fracture initiation pressure increases with bedding angles. An appreciable difference in fracture initiation pressure with SC CO2, SC CO2 foam and slick water are 5023psi, 6456psi and 6168psi, respectively at high conferment pressure (3500psi). Comparison of hydraulic fracturing of Eagle Ford, Wolfcamp and Mancos shale with different injection medium shows that SC CO2 foam produced complex fracture networks with high aperture and length for parallel, inclined and perpendicular perforations along the bedding. With all types of shale, SC CO2 foam injection has produced dense fracture network. Thus, fracturing with SC CO2 foam can potentially enhance the stimulated reservoir volume.
Artificial Lift System Applications for Thermally Developed Offshore Heavy Oil Reservoirs
Authors: Zhang Hua , Liu Pingli , Wang Qiuxia , Bai Jianhua , Zhang Wei , Zhang Hongwen , Han Xiaodong 
Published: March 2022

Abstract
The total crude oil resources are approximately 9-11 trillion barrels around the world and the steam based thermal recovery processes are still the most effective methods to enhance heavy oil recovery. Due to the high oil viscosity, high fluid temperature and high fluid volume changes with time, the choice of suitable artificial lift (AL) system is one of the most important techniques in optimizing production from thermally developed heavy oil wells.
Notwithstanding the attempt by several studies in the past few decades to understand and develop cutting-edge technologies to optimize the application of artificial lift system in thermally developed heavy oil reservoirs, there remains differing assessments of the best approach, AL type for various kinds of thermal recovery methods. A comprehensive review of artificial lift systems application with specific focus on thermally developed heavy oil reservoirs across the world for offshore oilfields is conducted. The review focuses on the special designed artificial lift system with functions of both steam injection and oil production for offshore oilfield. At the same time, the purpose of this work is to apprise the industry and academic researchers on the various AL optimization approaches that have been used and suggest AL optimization areas where new technologies can be developed for thermally developed heavy oil reservoirs in the future.
Holistic Analysis, Diagnostics and Operating Philosophy for Wellhead Leak Issue for Gas Producer, Offshore Malaysia
Authors: Barat Junnyaruin , Utta Arie Muchalis , Karpaya Shaturrvetan , Maluan Lilihani Binti , Lidwin Sharon Ellen 
Published: March 2022

Abstract
Since the beginning of production, well NA2 and NA3 wells had issues with wellhead integrity due to thermal growth and wellhead tilting. Seepage was observed from wellhead and based on gas chromatography test, the seepage is Synthetic Based Mud (SBM), possibly from B and C annulus (intermediate and surface casing). For well NA3, seepage was observed coming out from the connection of Casing Head and Drive Pipe Housing House (DPHH) while for Well A2, seepage was found between DPHH and conductor. The issues arise from the failed elastomer seals found at the connections of leak of each well suspected due to well growth/shrink and tilting which caused the wear and tear of the seals. The seepage of both wells was rectified by injecting the failed elastomer seals with pressure activated sealant to the P-seal and grease to the elastomer. Both wells managed to produce at the capped production rate without seepage as of today. Another main issue at Field N is the leaking of metal-to-metal seal at Xmas Tree which led to production deferment. Due to the failed barrier at surface, interim philosophy was established to operate the field and rectification plan was implemented to ensure the well is producing safely at the calculated risk.
This paper describes the analysis and diagnosis, operating philosophy outline by operator which led to the well safely producing at the desired rate: (1) Standing Instruction (SI) for Well Production Ramp Up and Down based on trending of production and temperature to ensure wellhead growth and tilting will not affecting the integrity of sealant, (2) Finite Element Analysis (FEA) and Wellhead Growth Study to develop operating limit and maximum allowable growth, correlated with well production and temperature, (3) logging and survey for well leak detection and echometer survey, (4) Wellhead Seal Injection for corrective maintenance upon seepage observed, (5) manual measurement of growth and tilting and utilizing laser sensor for automation, (6) External Slip Lock Brace Support (ESBS) Installation to mitigate abnormal relative growth and (7) risk assessment for well integrity.
The holistic approach in diagnostic, monitoring and operating philosophy enabled the well to be ramped up to higher production despite the threat of losing the gas production. PCSB also avoided the utilization of rig to rectify the well which resulted in cost avoidance for the company.