bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental Data for Wind Loads on Aframax Tanker, FSO, and FPSO
Authors: Abidin Mohd Hafiz Zainal , Rahman Hirzi Abd 
Published: February 2024

Abstract
The Wind Force coefficients published in OCIMF publication – Prediction of Wind and Current Load on VLCCs (Ref [1]) are widely used in the offshore industry to estimate wind loads acting on vessels. However, it is to be noted that the coefficients were calculated based on a typical VLCC-sized oil tanker. The applicability of the coefficients to different hull sizes and topside configurations may vary. Therefore, this study aims to validate the OCIMF coefficients by performing wind tunnel testing for a typical Aframax-sized tanker. Topside modules are added on the main deck to simulate different floater configurations.
Advancing Well Integrity Preservation in Workover Rig Intervention Via Instrumented Coiled Tubing and Through-Tubing Inflatable and Retrievable Packer Deployment: A South Kuwait Case Study
Authors: Chandrakar Yajuvendra Kumar , Al-Sarraf Abdullah , Slama Mohamed Hedi , Al-Ajmi Abdullah , Gupta Pravind , Badrawy Kareem , Sunagatov Rustem , Sebaih Mohannad Adel 
Published: February 2024

Abstract
The purpose of this paper is to present a case study of a pioneering step taken in restoring well integrity for workover rig intervention through the utilization of instrumented coiled tubing (CT) and through-tubing inflatable and retrievable packer (TTIRP) in South Kuwait Field.
In this particular instance, mechanical constraints at the christmas tree tubing hanger hindered the ability of the operator to install the blowout preventer (BOP) of the workover rig through conventional means. As a result, a custom-fit approach was implemented to enable the required number of pressure barriers to intervene the well.
The intervention approach employed the use of instrumented CT for barrier restoration, well killing and temporary well suspension. CT real-time downhole telemetry was utilized to ensure accurate placement and setting of the TTIRP within the production tubing. Once the packer integrity was pressure tested in both directions, CT was disconnected, and a sand plug followed by an acid soluble cement plug were placed on top of the TTIRP. Upon confirmation of cement plug integrity, the workover rig was utilized to install the BOP for intervention. The instrumented CT was then rigged up and run back-in-hole to clear the cement plug, circulate the sand out, and retrieve the TTIRP to the surface.
The candidate well where this innovative intervention workflow was implemented had a maximum potential wellhead pressure of nearly 1,500 psi and a plug-back true depth (PBTD) of 4,000 ft. The well was completed with 3 ½-in. production tubing set close to 3,500 ft MD and 8 5/8-in. casing until PBTD. An e-line through-tubing puncher was carried out in the production tubing before the first CT run to enable circulation of killing fluid. The TTIRP setting depth was conditioned via instrumented CT and high-pressure rotary jetting tool, resulting in a shut-in wellhead pressure near zero psi.
The results of this innovative intervention workflow were substantial, with an estimated saving of 195,000- bbl in deferred production (as the well was shut-in for at least 10 months). The lessons learned from this case study can now serve as a reference for operators in the Middle East with wells that present similar challenges.
Improving Well Productivity Post High-Density Mn3O4/BaSO4-Based Workover Fluids Formation Damage in HPHT Naturally Fractured Carbonate Gas Reservoirs
Authors: Alotaibi Nouf , Lawson-Jack Awoye , Smith Kern , Olaoluwa Salako , Chinea Gonzalo 
Published: February 2024

Abstract
High-density mud is typically considered for use in well kill during workover operations. Weighting agents such as barite (BaSO4) and (Mn3O4) are utilized to weight up drilling fluids during workover operations to provide the high-density requirement to balance the reservoir pressure with a safe margin and prevent unplanned and unwanted flow back of reservoir fluid into the wellbore in high pressure–high temperature (HPHT) naturally fractured carbonate gas reservoirs. However, these kill muds can result in formation damage and reduced well productivity post-workover causing the well to require stimulation treatment to restore its productivity.
Treatment evaluation at the laboratory level was conducted to determine the effectiveness of two fluid recipes: acid- and chelating-based, to remediate formation damage caused by high-density barite (BaSO4) and manganese tetraoxide (Mn3O4) weighting materials-based workover fluids.
A commercially available formation damage simulator was utilized to examine the impact of the workover and treatment fluids on reservoir core samples at downhole conditions. X-ray diffraction/X-ray fluorescence (XRD/XRF) analysis and a baseline computerized tomography (CT) scan of the reservoir core plugs were conducted before core flooding. Differential pressures along core samples were measured at controlled flow rates during nitrogen gas flooding before and after the workover (Mn3O4/BaSO4-based) and treatment fluids (acid- and chelating-based systems) application. Darcy's equation was used to calculate return permeability values and core plug CT scans post-floods were used to describe the productivity improvement mechanisms. Before treatment fluid selection for core-floods, the laboratory rock and fluid compatibility testing were conducted.
The laboratory results obtained confirm both the acid- and chelating-based treatment fluids were able to improve the well productivity by fully restoring the core permeability with a negative skin by creating wormholes/pinholes throughout the carbonate core plugs and by dissolving/breaking down the filter cakes. This paper presents a systematic treatment solution formulation and laboratory-based testing of treatment fluid's effectiveness in restoring productivity of Mn3O4 and BaSO4-based workover fluids formation damaged wells.
Implementation of Compact Carbon Capture Modules on Offshore Hydrocarbon Production Facilities
Authors: Tan Jaime HuiChoo , Hassan Rizal Aslan , Cornelis Umberto , Jackson Sabine 
Published: February 2024

Abstract
Carbon capture and storage (CCS) have been successfully implemented onshore by different industries, including utilities and waste treatment, to capture the carbon dioxide (CO2) from the flue gases after the combustion of fossil fuels. To duplicate this success for offshore hydrocarbon processing facilities can be challenging due to the facility deck space constraints and marine environmental conditions. Innovative compact carbon capture modules for gas turbine (GT) exhaust gas CO2 capture have recently been developed taking these constraints into account for applications on large offshore oil and gas facilities such as Floating Production, Storage and Offloading (FPSO) facilities and Floating Liquefied Natural Gas (FLNG) facilities, as well as relatively smaller fixed-bottom platforms such as Central Production Platforms (CPPs).
This paper describes the design of the compact carbon capture modules including the post-combustion CO2 removal process technology used, for applications on offshore facilities. A carbon capture system which removes CO2 using a proprietary amine-based solvent and absorption technique is powering these compact carbon capture modules. The described carbon capture module design is suitable for applications on new as well as existing offshore facilities. For implementation of the carbon capture modules on typical CPP and FPSO/FLNG facilities, the utility requirements and facility layout design are described in this paper. It is demonstrated that deploying amine-based carbon capture technology offshore is now feasible using these lighter-weight and smaller-footprint carbon capture modules, significantly reducing CO2 emissions from GT power generation systems.
Multiscale Upscaling Study for CO2 Storage in Carbonate Rocks Using Machine Learning and Multiscale Imaging
Authors: Yong Wen Pin , Menke Hannah , Maes Julien , Geiger Sebastian , Bakar Zainol Affendi Abu , Lewis Helen , Buckman Jim , Bonnin Anne , Singh Kamaljit 
Published: February 2024

Abstract
Microporosity is commonly assumed to be non-connected porosity and not commonly studied in geoengineering industry. However, the presence of micropores plays a key role in connecting macropores and it can contribute significantly to the overall flow performance. In this study, targeted CO2 storage carbonate fields in Southeast Asia have significant amounts of microporosity ranging from 10 to 60% of the total measured porosity. Microporosity can only be seen in high resolution images. To study the unresolved and the resolved microporosity, Middle Miocene carbonate samples from CO2 storage candidate fields were scanned using lower resolution micro-computed micro-tomography (micro-CT) and higher resolution synchrotron light source to understand the pore scale structure of the carbonate sample at different length scales. This paper proposes a proof-of-concept upscaling method that integrates multiscale 3D imaging techniques and trendline analysis to establish porosity-permeability relationships with microporosity insight. After image acquisition and processing, the images were divided into smaller sub-volumes. Pore-scale modelling was conducted to predict the permeability using Darcy-Brinkman-Stokes (DBS) model. Then, a nano-scale porosity-permeability transform is generated using natural log trendline fitting based on simulation results. The porosity-permeability transform is further extended to three cases to cover the low case, mid case, and high case of datapoint fittings and is further validated with laboratory measured data. The established porosity-permeability transforms in this study have been applied to compare with petrophysical derived porosity-permeability transforms with better performance (higher R2 value) for low permeability datapoint. The multiscale imaging upscaling workflow has integrated machine learning during image segmentation with pore-scale modelling and trendline fitting during the upscaling study. It emphasises the importance of seeing the unseen (unresolved microporous phase) to understand the internal texture and microstructure of a rock sample in order to understand the connectivity of the overall flow performance in a carbonate rock.
Pilot Tests of Steam Flooding after Cyclic Steam-N2-CO2 Stimulation in Bohai Offshore with Large Well Spacing
Authors: Liu Dong , Liu Zongbin , Pan Guangming , Chen Jianbo , Liao Hui , Li Hao 
Published: February 2024

Abstract
Two challenges confront the development of Bohai heavy oil resources: first is the high development costs, which requires an economic limit production of 100,000 m3 for a single well; in addition, the unfavorable geological conditions, including thin payzones and deep burial, cause serious heat losses and unsatisfactory oil recovery under large well spacings. Therefore, this study aims to solve such technical issues as "efficient production with fewer wells" and "high recovery with large well spacings".
A recovery strategy is developed: improved recovery efficiency during the Cyclic Steam-N2-CO2 Stimulation (CSS) stage, and effective conversion from CSS to steam flooding (SF), and uniform heating the reservoir during the SF stage. This attempts to address the inefficient heating in thin pay zones, lack of experiences on SF-after-CSS with large well spacings, and difficult control of temperature field under irregular well patterns.
Learnings are summarized as following: (1) A new technique, weak gel-gas-chemical agent assisted CSS, is proposed. The co-injection results in relatively higher cycle oil production and smaller steam-oil ratio after multiple cycles. The oil recovery is improved from 23.0% to 32.8%, and return on investment (ROI) from 1:1 to 9:1. (2) The threshold pressure gradient is dynamically characterized for offshore wells with large-well spacings. Quantitative identification for the timing for CSS-to-SF is established on the basis of reservoir temperatures. The threshold well spacing is increased from 80 m to 200-300 m, and the corresponding oil recovery boosted from 32.8% to 43.5%. (3) On the basis of the three-level architecture characterization of meandering river sand body, a method is proposed to adjust the temperature field in the reservoir during the SF stage. It improves the aerial sweep between large-spaced wells from 72% to 87% and the oil recovery from 43.5% to 47.0%. (4) The aforementioned techniques have been applied in NB35 reservoir and obtained success, which achieved an incremental oil production of 38.5×104 t and a recovery degree of 32% in the pilot test area.
The study proved SF as a feasible follow-up process of CSS in offshore heavy oil reservoirs with deep burial, thin pay zones, and large well spacings. It provides great support for the efficient development of Bohai offshore oilfield, as well as a new direction for similar reservoirs in the world.
Sustainable Bio-Based cEOR Formulation for a Challenging Indonesian High Temperature Carbonate Reservoir
Authors: Sari A. , _ Sarah , Fitor Y. , Prasetyo A. B. , Iskandar U. P. , Alli Y. F. , Wangge Y. B. D. , Koh H. M. , Chow S. B. , Roy S. , Rilian N. A. 
Published: February 2024

Abstract
Enhanced Oil Recovery (EOR) becomes increasingly important as the global crude oil reserves are being depleted. This is especially true in Indonesia where the growing internal demand exceeds its oil production as many fields are in their mature stages and thereby slowing down the overall oil production rate. Thus, it is imperative for Indonesia to look for alternative strategies to improve production from the maturing fields by adopting various tertiary techniques in order to achieve a national target of 1 MMBOPD oil production by 2030.
Field X is an onshore mature carbonate field that has been identified as a potential chemical EOR candidate. Carbonate reservoirs with moderate high reservoir temperature, 90 °C in the case of Field X, are known to be creating additional challenges for chemical EOR, particularly in formulating a tailored surfactant blend that exhibits stable behaviour, high performance and trouble-free operations.
In this paper, the surfactant-polymer (SP) formulation design, optimization and lessons learnt leading up to a successful bio-based robust chemical EOR formulation with suitable adsorption strategy for relatively low salinity (8000-9000 ppm of salinity) and high temperature (90 °C) carbonate field are presented. A multi component surfactant formulation using a novel bio-based surfactant, internal ketone sulfonate (IKS), as a primary surfactant was designed for the high temperature X reservoir. The raw materials for producing IKS surfactant that is used in this formulation is sourced and manufactured in Indonesia which also in turn creates circular economy benefits. In addition, the use of bio-based surfactant chemistry greatly decreases the carbon footprint compared to petroleum-derived chemicals and IKS has the significant advantage of improved raw material availability. The SP formulation was evaluated following a systematic workflow in order to achieve good thermal stability, SP compatibility, ultra-low interfacial tension (IFT) and favourable residual oil production with managed surfactant adsorption mitigation.
As expected, the main challenge was the reservoir conditions and the nature of rock during the course of this study which resulted in a very promising oil recovery strategy in economically realistic conditions using sustainable bio-based chemistry.
Record-Breaking on Wireline Data Acquisition: Leveraging Large Dimension of Wireline Formation Tester in Slim Hole and High Deviation Well – Pushing the Boundaries of Wellbore Clearance Issue
Authors: Siregar R. , Jamduong C. , Bari S. , Pongpruksatol T. , Nimchinda P. , Grattan T. , Maurer R. 
Published: February 2024

Abstract
The gas-fields in the north Malay Basin and Gulf of Thailand region are well-known with the presence of high CO2 and H2S concentration in the reservoirs. Sophisticated and robust tools are needed to measure important data in order to support further development and reservoir management of the field. Thus, reservoir data such as pressure and fluid type become crucial in achieving the production target and reservoir management of this field. Fields are located in the North Malay Basin, a few hundred kilometres from the onshore border of Malaysia and Thailand. This paper describes deploying large dimension of wireline formation tester in slim hole and high deviation well which the tool option is limited in the current market.
The well design with slim hole 6-1/8" high deviation in the pay zone interval brings with them operational challenges for deploying wireline logging a critical direct measurement of downhole fluid analysis (DFA) and obtain low contamination sample which unable to provide accurate measurement under slim hole. As the Wireline formation testing (WFT) which equipped with pump out capability in the market is limited. The existing slim – WFT which can provide only a limited pumping volume leads the operator to find alternative methods due to the limitation of direct measurement to require downhole data. Hence, a more popular WFT with larger pump volume is required. A combination using a large volume WFT equipped with rollers and articulated hole finder (AHF) are appropriate to acquire downhole fluid information.
The ability of fluid characterization using a pump out formation tester coupled with downhole fluid identification has been introduced to aim an accurate decision and provide real-time data. Capability to pump-out formation fluid and acquire sample that met the expectation of contamination levels. As a result, successful determination of fluid contact, formation pressure, fluid type, reservoir mobility, and CO2 content which are the main driver to production optimization and field development. In addition, wireline data acquisition is accessible in slim hole 6-1/8" high deviation, bring more options the tool availability in the current market as only few contractors are able to provide those technologies. Using this structured approach to wireline conveyance, the operations were successfully accomplished and met the well objectives by performing pressure tests and sampling with adequate stationary time resulting in significant savings for the operator.
Deploying large dimensions of WFT in slim hole 6-1/8" high deviation wells are often a source concern for subsurface, drilling and service company personnel. However, this is the first ever implementation in the region and worldwide which pushing the limitation of the tool deployment and alternative options for operators with the well design alike.
Advancing a Large-Scale Carbon Capture, Transport and Offshore Storage Solution Towards Net Zero
Authors: Chew R. , Wettland F. , Hammervold E. , Bo J. Koll-Hansen , Syverud T. 
Published: February 2024

Abstract
To limit global warming to 1.5°C and reduce GHG emissions in line with the European Climate Law, large-scale deployment of carbon capture and storage (CCS) infrastructure is critical to achieving the net zero targets. The European Commission is promoting CCS as a strategic climate technology for decarbonizing hard-to-abate sectors, and as a platform for carbon dioxide removals. However, access to CO2 storage sites remains a key constraint for accelerating CCS deployment. The objective is to advance a large-scale carbon capture and storage (CCS) solution in order to develop a flexible, scalable, open-access CO2 collection, transport and storage infrastructure comprised of: CO2 terminals for onshore collection and processing to low-temperature, low-pressure liquid CO2 and LCO2 carriers that will transport the CO2 to an offshore floating injection unit (FIU) that will inject the CO2 into a deep saline aquifer for permanent storage.
Subsea Compression: Sustainably Unlocking Subsea Gas Resources to Any Scale
Authors: Lupeau Alexandre , Barras Nicolas , Godoe Sjur , Almqvist Joakim , Vielliard Christophe 
Published: February 2024

Abstract
The drastic reduction of greenhouse gas emissions set to the energy sector has to happen while the world continues to face an increasing demand in energy to fuel global development. To solve this complex equation the transition to gas production to enhance the existing energy mix is a recognized step to produce more affordable energy with reduced carbon footprint. Many of the gas resources still available today are subsea and bring with them specific subsea production challenges.
During the last decades the subsea industry has developed, qualified, and deployed advanced production technologies capable of significantly enhancing the recovery factor of subsea assets. Subsea boosting and processing technologies have now been deployed in many fields over the globe. They have proven their reliability and efficiency to extract more hydrocarbon from subsea reservoirs. They represent a game changing opportunity to boost the productivity of future subsea gas production while reducing the total cost of ownership of subsea assets as well as their associated carbon intensity.
Subsea compression takes advantage of more than 25 years of advancements in the boosting domain. The lessons learned in the subsea boosting domain provide an unparalleled experience with over 120 systems delivered across the globe, totaling close to 5 million hours of cumulated operating time. The benefits of subsea compression are particularly evident for deep waters and long tiebacks. Studies show that the reservoir recovery factor can be increased, to give up to 25% more gas while the total power required per volume produced can be reduced by more than 60% if subsea compression is used.
With two systems already in operation and two projects currently in execution, subsea compression proves to be a mature solution to boost subsea gas production for a large spectrum of field configurations and flow conditions. From simple system architectures capable of boosting the unprocessed wet gas stream to a more advanced solution where separation of gas and liquid is applied, the proven subsea compression technology bricks offer a unique flexibility and scalability to accommodate a wide range of reservoir sizes and system constraints. In other words, sustainably unlocking subsea gas resources to any scale.