bluuebunny/crossref_metadata_2025 huggingface dataset:
Risk Based Determination of Pipeline Safety System Using Quantitative Pipeline Risk Assessment Approach
Authors: Mohd Ali Napiah Mohd Nazmi , Morad Halimi B , M Rashid M Nizam , Abdullah Nur Asiah , Idris Naila Rusma
Published: November 2020

Pipeline Leak Detection System (PLDS) is a hardware and/or software-based monitoring tools that is utilized to indicate a leak or hydrocarbon release along the pipeline. However, it is noted that most pipelines are not equipped with PLDS as risks associated with the pipeline are mitigated by other means or deemed low. Another issue is that the current leak detection technology is not a full proof system i.e. it may still be giving false leak alarms or inaccuracies in the leak location.

PETRONAS Procedures and Guidelines for Upstream Activities (PPGUA) calls for installation of Subsea Safety Isolation Valve (SSIV) for protection and risk mitigation measures to the new pipeline installed, particularly for gas pipelines or where pipelines are connected into major trunk pipeline systems with large connected inventories. A justification shall be provided if SSIV are not installed.

A risk assessment study and cost benefit analysis should be performed to justify the use of PLDS and installation of SSIV. High risk pipelines such as those transporting volatile, corrosive, flammable or toxic fluids in significant volume in high consequence areas may benefit from the use of PLDS and SSIV in limiting the inventory leaked to the environment and the resulting consequence.

PETRONAS Technical Standard (PTS) specifies that the requirement for PLDS and SSIV for new pipelines is to be determined via a semi-quantitative Risk Assessment or a fully Quantitative Risk Assessment (QRA).
Tender Assisted Drilling: A World First Approach to Reactivate an Idle Platform Rig in Deepwater Angola
Authors: Le Guen Jean-Christophe
Published: November 2020

The objective of this paper is to present the novel approach that the drilling contractor implemented for an operator in West Africa confronted with significant reactivation/recertification costs for one of its idle integrated platform rig.

The drilling contractor proposed to couple the platform rig to one of their existing tender vessel, that is usually used to assist its own drilling rig, creating the first ever hybrid platform rig assisted by a tender vessel. The tender vessel was mobilized alongside the platform during the reactivation phase, offering ample POB capacity and avoiding the hiring of accommodation vessel, then the power and fluid system were hooked up to platform equipments that were to be used.

This approach avoided the refurbishment/overhaul/recertification of the main and emergengy engine, the mud pumps and the mud pits and all the auxiliary systems that support the rig equipement. For the operator' s eighteen month workover and drilling campaign, the drilling contractor also proposed a cost-effective approach, looking into their available capital equipment inventory for compatible equipment still under certification. Once identified, the equipment were simply swapped so no additional recertification cost was required.

The drilling contractor took the opportunity of this major reactivation to review completely the working flow of the rig and proposed a new offline pipe handling system and upgrade the online one, to improve the rig overall performance compare to the original design.

All these novel approaches are reducing the overall project cost by 20% compare to a refurbishment of existing rig by OEM and introduce the offline pipe handling bringing an additional minimum 5% of operation time saving, making the project viable.

The use of a tender vessel along a platform, feeding the platform rig equipment with power and fluids to extend the platform life is a novel approach in the industry that offer significant cost saving for operator suffering prohibitive reactivation/recertification costs of an idle fixed platform rig or any operator looking to reduce equipment weight on aging platforms. This paper will describe the major modifications that were required to make this world first attempt a success.
Advances in Applying Continuous Pack-off Inflow Control Device for a Water and Sand Control Reservoir in South China Sea
Authors: Xiong Shuquan , Li Fan , Cheng Chuchuan , Wu Sijia , Pei Bailin , Dai Chaoyong
Published: November 2020

The production in oilfield "A" in South China Sea is reducing dramatically, with known fine-grain migration into the near-wellbore area. The heavy oil inunconsolidated sandstone is water drive reservoir. It featured high content of clay (>10%). Gravel packing and screen are used to prevent the sand production.Oil recovery is low due to the water-break through (WBT) in this field.

Continuous Pack-off Inflow Control Devices (CPI) is a proprietary water controltechnique including two operational steps: first run ICD strings,and theninject special designed proppants into the wellbore annulus. The results show this technique iscost-effective, and reliable oil recovery method.

This paper presents a method of using ICD and CPI particles to maximize oil recovery in sandstones.Compared with other water control methods, the CPI advanced them by delaying/reducing water invasion. The case stuy in the well showntheproductionis stablein 12 months without sanding issue. wellswith ICD andswellable packers often lost production because of the accumulation of the fine- grain and plugging around the screens. The wellwith gravel packing reached water cut of 70 % at a cumulative oil of 6000 cubic meters whilethe well with CPI technique shown water cut of 10 %when produced 6000 cubic meters oil.
Integrate Surface Facilities with Reservoir Resources to Make the Small Offshore Oil Field Fruitful
Authors: Su Yanchun , Shi Hongfu , He Yifan
Published: November 2020

Marginal oilfields refer to the development of oilfields with insufficient economic benefits by conventional methods under current economic conditions due to objective reasons (geological reserves, geographical location, development technology, engineering investment and taxation, etc.). In China, after nearly 30 years of large-scale offshore oil exploration and development, a large number of high-quality large and medium oilfields have been proven in offshore areas such as the Bohai Bay, South China Sea, and East China Sea. With the deepening of exploration and development, newly discovered oil fields belong to small marginal oil fields. Generally, the oil or gas reserves are limited, the structure is broken and complicated or they are located in remote areas. It has poor economic benefits with conventional development technology due to low output, large one-time investment in the construction of production platforms and the laying of subsea pipelines, and a long period of capital return. It is not attractive for cooperative development with foreign investors. Offshore marginal oil fields often lose commercial exploitation value due to mismatches in reserves and production with development costs.
Evaluation of Different Well Converting Patterns with the Distribution of Streamlines on Ultra High Water Cut Reservoir
Authors: Wang Huiyu , Hou Jian , Guo Zhenhai , He Sixian , Du Qingjun , Li Cheng
Published: November 2020

The mutual converting between production and injection well can be applied to change the directions of streamlines to improve the sweep efficiency of zone with high residual oil. How to improve the oil recovery by efficiently developing the remaining oil is a key issue for ultra-high water-cut reservoir. Therefore, based on a realistic reservoir selected from Shengli Oil-field, a model is presented to investigate the effects of different converting patterns on ultra-high water cut reservoir.

In this work, we built the model in Eclipse of Schlumberger according to the real well pattern and reservoir conditions. The residual oil distribution after water-flooding under ultra-high water cut was studied. Then, to obtain the optimal oil recovery, we investigated four well converting patterns, including the distribution of modified streamlines and final oil recovery. Moreover, we investigated the effects of water cut which is the time to convert and permeability ratio on residual oil recovery. All patterns and the model is described in detail to permit readers to replicate all results.

According to the simulation results, the shape of residual oil distribution of traditional five-point pattern is like a cross which is around the production well. Comparisons of oil recovery of four converting patterns are presented. The optimal case is the pattern which applies well converting in an interval way, arranging one injection well between two production wells. This interval way is able to let streamlines sweep more areas with high oil saturation. Whether high oil recovery can be received also depends on two significant parameters-water cut and permeability ratio. For water cut, there is an optimal number when applying this method. In this study, the converting should be applied when water cut is 93%. For permeability ratio, the higher it is, the higher oil recovery we can have after applying the converting. Both two parameters are combined to obtain the best water cut to convert with different permeability ratios.

Due to high cost of many EORs like chemical flooding, the novelty of this work is in the ability to provide a more cost-effective and convenient method to address the low oil recovery of high water cut oil-fields.
Introducing New Drone-Based Inspection Technologies to Safely and Consistently Deliver High Value Results
Authors: Moonen A. J. , Sufian Bin Ahmad
Published: November 2020

Over the past few years ‘Drones’ (or Unmanned Aerial Systems as they are offcially called) have become an accepted part of the inspection ‘toolkit’ in upstream and downstream oil & gas. Yet, at the moment, their application in the oil & gas industry is still largely limited to pure visual inspection of tall structures (e.g., flares, communication towers and offshore jacket structures) or visual surveying of pipelines and construction sites with some occasional use of thermography as well. As drone technology is becoming more and more common, the call to expand their use with other inspection and surveying techniques is also becoming louder. Fortunately, developments are now underway to add capabilities, e.g. (i) ultrasonic thickness gauging (UTG), (ii) ultrasonic defect detection, (iii) detection of hydrocarbon leaks by Optical Gas Imaging (OGI), (iv) internal inspection of membrane LNG cargo tanks, (v) 3D mapping of structures through either LiDAR or photogrammetry, and (iv) ultra long range operations (5 hours flight time and above) to survey unmanned offshore facilities.

By definition the oil & gas environment is challenging and high-risk. Thus, to introduce these technologies, it is not sufficient to ‘slap a new probe or sensor on a drone’ or to buy a new, more capable drone and then perform a few proof-of-concept flights for a successful operational introduction. The successful ‘hardening’ of new technologies for drone inspections or surveillance in a real-life operational environment requires the integration of equipment, crew capabilities, procedures and data management. Therefore, for every new step, a full development cycle has to be organised and managed. A bespoke safety case underpins cycle by generating the key elements from which (additional) training as well as operational procedures and data management tools/processes can be developed. Extensive trialing and milestone reviews are part of the process.

Only if the young but growing ‘drone services’ industry and asset owners follow such a systematic development approach in a disciplined manner will it be possible to ensure the safety, consistency and quality of ‘drone-based inspections’. Without this, the outcomes will at best be disappointing. This paper presents the first comprehensive description of such an approach. Drone-based ultrasonic inspections are used as a real-life example.
Winning Over the Production Threat: An Innovative Petrophysical Approach for Sand Grain Size Prediction and Rock Strength Evaluation
Authors: Zulkipli Siti Najmi , Johar Zurita
Published: November 2020

Majority of producing reservoirs in Malaysia come from sandstone accumulation with varying properties, rock fabrics and qualities. Being one of the major culprits in development and production spectrum, failure to take proactive measures for early prevention and detection of sanding issue has proved to be an expensive lesson learned especially during the mature production stage and late field life. High cost, increasing risk and intervention complexity and massive revenue loss are among the consequences due to this failure. This paper will highlight the challenges faced in sand prediction and monitoring and the proposed solutions at various field stages incorporating subsurface analysis, technology and brilliance at basics. The same approach will be used in rock strength evaluation for field subsidence analysis.

Subsurface data such as logs, cores, drill cuttings and downhole well configuration can offer a tremendous insight at early stage of sanding issue. During field exploration and appraisal phase, information on reservoir compaction, barrier and heterogeneity, grain size, clay types and fines accumulation are usually investigated to give the overall reservoir potential and productivity overview. More comprehensive study could be conducted if core is available such as compressive strength, pore volume compressibility, elastic properties and even flooding test to simulate formation damage and factors affecting sand production. In area where limited core data is available, logs can be used to predict and generate sanding parameters such as grain size and other rock strength properties, hence driving the completion optimisation efforts and sand production preventive measures. Once production commences, sand count and particle size mapping should be updated frequently to complement the monitoring program.

Leveraging on technology and collaboration, downhole logging acquisition to locate sand producing interval, chemical based sand consolidation treatment and core-driven sand screen selection and gravel size design are among the common scenarios taking place to help with production revival. Results generated from subsurface study will be input to the early formulation of field development plan and production strategy especially for downhole as well as surface sand control mechanism. In addition, integrated grain size and rock strength prediction workflow had been formulated based on logs to provide a competitive framework for time and cost optimization.

Case studies presented in this paper will demonstrate a holistic and integrated approach at each stage of field life to win over the sand production hurdle as well as minimizing threat to production sustainability. Banishing the emerging threat through comprehensive subsurface study, strategic planning, execution and monitoring become the main agenda to protect well integrity as well as safeguarding the production.
Influence of Microwave Irradiated Plantain Peel Starch on its Performance as Water-Based Mud Fluid Loss Control
Authors: Awel Ferreira Ashley , Momeni Mohammadsadegh , Liew Hui Ling Jacklyn , Ghomali Raoof , Safari Mehdi
Published: November 2020

This research studies the potential of microwave irradiated plantain peels starch as additive to minimize the filtrate in water-based drilling fluids. The fact of agro-waste rapid growth has become centre of this research. Also, problem induced by filtration loss into the formation encourages research in this study. The formulation for the mud were prepared by using the standard mixture and added with different concentration of plantain peel starch. The novelty of this study is the investigation on the effect of microwave treatment on the properties of plantain peels starch which affects the performance of the drilling fluid.

The influence of the non-ionizing microwave effect on starch changed the physical and chemical properties by the disintegrated intermolecular bonding of the starch particles. Microwave heating reduced the moisture content of the starch by 81% due to rapid heat transfer within the starch granule. The water binding capacity of the starch has increased by 42.4% as compared to the non-microwaved starch. The swelling power curve increased to the factor of 3 and as temperature reaching 80?C the factor reduced to 1.5. Solubility curve of microwaved starch is on the other hand lays below the non-microwaved curve shows that microwave irradiation decreased the solubility of the starch.

Next, the performance of mud is evaluated with the presence of different concentration of native and microwave irradiated starch. Plantain peel starch did not affect the mud weight. The starch additives did not alter the pH and the mud pH is in the accepted alkali range. The starch concentration is directly affecting the viscosity of the mud. The presence of the starch in the mud enhanced the viscosity of the mud and also the yield point which favours the drilling operation as yield point indicates the ability of mud to transport cutting to the surface. Simultaneously, gel strength of the mud also improved with the presence of plantain peel starch and further enhanced with the presence of microwaved irradiated starch. In addition, plantain peel starch improved the fluid loss volume and further ameliorated the fluid loss when the microwave-treated starch added in the mixtures.
Waterflood Evaluation and Optimisation Through Rapid InterwellConnectivity Modelling in a Complex Reservoir
Authors: A. Salam Irzie Hani , Hendraningrat Luky , Idris Nurul Nadhira , Yakup Muhammad Hamzi , Rinadi Muhammad , Sedaralit Mohammad Faizal
Published: November 2020

Waterflood is well-known as the cost effective secondary recovery mechanism to improve oil recovery. With current challenging oil price environment, waterflood continues to be one of the main candidate of choice. Hence, it is very important to maximize by optimizing the process. The objective of this paper is to propose a rapid technique to evaluate and optimize current matured waterflooding project in an offshore brown field with complex stacked reservoirs and production system through dynamic data analyses.

Interwell connectivity evaluation can assist in reservoir characterization, well placement, and evaluate waterflooding performance. Therefore, dynamic data analytics workflow applying interwell connectivity evaluation and Streamline as implicit approach are proposed. The importance of clustering each area become important to raise particular issues such as poor properties and connectivity. The production and injection points are evaluated and unswept area can be identified. Therefore, waterflood can be optimized.

This study resulted if current waterflooding can be optimized and new potential well placement can be identified to increase oil recovery. Compared with no further action case, oil recovery can be potentially improved 3-4% based on numerical full-field modelling prediction.

The technique will be very useful to have business decision rapidly in weeks. With current oil price situation, it can be as a cost-effective technique, especially for brown fields with mature waterflood projects and have complexity in geological and production system that commonly time consumption. The proposed workflow can be deployed to other neighbor mature fields.
Methodology of Simulating Spread-Moored FPSO Green Water Using CFD-Based Numerical Wave Basin
Authors: Teng YihJeng , Tan Jaime HuiChoo , Kim Jang , Jang Hyunchul , Lim Ho-Joon , Kyoung Johyun , Tcherniguin Nicolas
Published: November 2020

This paper presents the methodology of simulating green water events of a spread-moored FPSO platform using a CFD-based Numerical Wave Basin (NWB) with an optimized CFD model. Previous work done on the assessment of the motions of the spread-moored FPSO platform in irregular waves has demonstrated excellent agreement between CFD calculation and model test measurement (Baquet et al., 2019). This study further investigates the CFD methodology to efficiently simulate highly non-linear/breaking waves to extend the NWB applications to include prediction of green water occurrence on FPSO platforms.

In this study, a CFD model is developed to enable efficient and direct simulation of green water events identified from global motion analysis of the FPSO platform. Smaller time-steps are used, and mesh refinement is applied at the regions which are potentially subjected to green water to ensure more accurate prediction of the green water elevations could be achieved compared to the global motion analysis model. The computing resources required to run the CFD model are maintained below the practical limits for use during typical FPSO project engineering phase. CFD model simulation results for green water events of the FPSO platform are compared against available model test data and good agreement is observed.

This paper demonstrates an application of CFD-based NWB for green water prediction for a spread-moored FPSO platform based on an optimized CFD model which is developed to enable fast simulation of green water events. To evaluate the susceptibility of a FPSO platform to green water, large numbers of green water event simulations will be required to obtain reliable statistical data.
Effect of Thermal/Shear Conditioning and Aging on the Effectiveness of Synthesized Nanocomposite PPD on Waxy Crude Oil
Authors: Sharma Rohit , Mahto Vikas , Vuthaluru Hari , Li Chun-Zhu
Published: November 2020

Wax deposition is a serious issue during the pipeline transportation of crude oil. This research work has investigated the effects of some important parameters on the flow characteristic of crude oil during the pipeline transportation in offshore and onshore field environments.i.e. effects of thermal/shear conditioning and aging on the flow properties of virgin crude oil and additive-treated crude oil. Polymeric nanocomposites are a new and improved family of pour point depressants that can enhance the performance of polymeric additives. This work is in continuation of our previous work of Sharma et al. 2019c, where polymeric nanocomposites based on graphene oxide were synthesized, namely poly (methyl methacrylate)-graphene oxide [PMMA-GO] with different concentrations of graphene oxide (0.5, 1 wt. %), and were subsequently evaluated as potential pour point depressants for a waxy Indian crude oil possessing substantial wax deposition and gelation issues. The effectiveness of the PMMA-GO was examined in this work based on its pour point depression, flow performance, and enduring thermal conditioning, shear conditioning and aging phenomenon in the PMMA-GO treated crude oil. Its performance was compared to that of polymer PMMA-treated crude oil, and a PPD-wax interaction mechanism was proposed. The effects of thermal conditioning on the performance of PPDs were evaluated by determining the gelation points at cooling rates of 0.5, 1 and 1.5°C/min. Also, the pour points of additive-treated crude samples were calculated after repetitive heating at temperatures 60°C, 55°C, 50°C and 45°C. The effects of aging on the flow behaviour of crude oil were determined by obtaining the rheological properties and pour point values on the 1st and 15th day of its storage. For evaluation under shear conditioning, apparent viscosities were measured over shear rates of 0.1-500 s-1 at temperatures 30°C, 40°C and 50°C below and near wax appearance temperature (WAT). This study complements the benefits of the PMMA-GO as a flow improver obtained in our previous study and details its effectiveness under more practical applications.
Mesh Learning: A Cloud and Edge–based Computing Network Providing Data–Driven Solutions to the Oil and Gas Industry
Authors: Wen Tailai , Dobson Ellie , Hvaara Roy
Published: November 2020

Over the past decade, the application of machine learning has become one of the most studied topics in the oil and gas industry. The recent success of some small-scale pilot projects has resulted in more attention being paid to deploying machine learning models at scale for operations. While cloud-based deployment (data backhauled for analysis in the cloud) and edge-based deployment (data being analyzed locally at a remote site without persistent Internet connection) are the two major approaches, each strategy has specific advantages and drawbacks. In this paper, we proposed "mesh learning", a new approach that optimally balances cloud computing and edge computing for deploying machine learning solutions in an industrial internet of things (IIoT) environment. We present how the system enables some new strategies to manage machine learning model lifecycles and how it helps with relevant use cases for the oil and gas industry.
Drilling Geomechanics Successfully Applied in a High-Temperature High-Pressure Offshore Well, South China Sea
Authors: Wang Shiyue , Liu Peng , Guo Shusheng , Gao Yongde , Chen Ming , Du Chao
Published: November 2020

Drilling in Yinggehai basin of South China Sea is challenging due to high pressure gradient (2.20-2.30 g/cm3) and high temperature (186-196 0C). Several wells did not reach target and were abandoned due to severe wellbore instability of gas kick and mud loss. In order to drill safely, drilling geomechanics techniques were applied in well LD-6, including: 1) real-time monitored pore pressure and fracture pressure with logging while drilling (LWD) technique; 2) predicted over-pressured reservoir depth and formation pressure ahead of bit with borehole vertical seismic profile (VSP); 3) wellbore stability analysis to reveal the mechanism of mud loss in Huangliu formation.

With drilling geomechanics techniques, well LD-6 was successfully drilled and completed. The achievements were:1) formation pore pressure and fracture pressure were accurately monitored while drilling. The predicted reservoir pore pressure gradient was 2.27g/cm3 and actual measurement was 2.28 g/cm3; 2) The top depth of over-pressured reservoir, S1 Sand, was predicted within 3 meters versus actual depth. The 9-5/8" casing successfully set in shale formation above S1 Sand, which enabled a manageable pressure window for drilling 8-3/8" reservoir section; 3) the wellbore stability analysis with borehole resistivity image revealed that mud loss only occurred in sand and mainly caused by drilling-induced tensile fractures. Stresses computation results indicated that horizontal stress anisotropy in sand is larger than shale; and breakdown pressure in sand is smaller than that in shale. With this finding, drilling parameters was adjusted accordingly and managed downhole pressure within the narrow safe mud weight window.

The drilling experiences in well LD-6 has proved the advantages of drilling geomechanics techniques, especially in HTHP area. It can predict and mitigate drilling risks, optimize mud weight and completion diagram, improve operational safety and reduce costs.
A Systematic Characterization of a Novel Diamond-Like Coating to Reduce Solids Deposition in Production Systems
Authors: Heydrich Marcus , Choudhary Suresh , Hammami Ahmed , Ratulowski John , Bukuaghangin Ogbemi , Charpentier Thibaut , Neville Anne
Published: November 2020

Deposition of inorganic and organic solids in production systems impacts throughput and can cause other operational and safety issues. Once formed, remediation of deposits is costly, often resulting in lost production. Solids management strategies involve a combination of chemical injection, thermal management and periodic chemical or mechanical remediation operations specific for each depositing species. A novel diamond-like carbon (DLC) coating, which exhibits extreme hydrophobicity in oil water systems, has been developed to control deposition of most common solids including asphaltenes, inorganic scale, wax and potentially hydrates under flowing conditions in production tubing and flowlines. This molecularly bonded, multifunctional coating may simplify solids management strategies and lower field development costs by reducing chemical injection, eliminating chemical injection systems, reducing insulation and eliminating the need for active heating. In this paper, we build on previous published data further refining the performance envelopes of the coating for inorganic scales.

Previously published work has shown that this coating is effective in managing wax and asphaltene depositions. Over forty tests in a 2-inch flow loop were used to define an operating envelop as a function of wall shear and δT in which little or no wax deposition occurs. This envelop covers much of the operational range of typical production systems. A Couettte shear cell, Organic Solids Deposition and Control (OSDC) [Zougari et al, 2006], was used to test the deposition tendency of asphaltene on the coated surface at wall shears representative of field conditions. Both live oil and dead oil tests showed a significant reduction of deposits on the coated surface for the two oils tested.

Initial testing for calcite deposition tendency was performed using a benchtop Rotating Cylinder Electrode (RCE) device. Also, small scale flow loop tests were done to determine the impact of the coating on halite and barite deposition. The coating resulted in a reduction of deposition rate for both calcite and halite. For barite, there was a significant reduction in adhesion force between the scale and the coated tubing resulting in an easily remediated deposit. In this paper, we further refine the performance envelopes for calcite and barite with a systematic study investigating the impact of brine composition, wall shear rate and the presence of oil on both deposition tendency and adhesion force.

Based on the positive results of the performance testing, a commercial-scale application facility has been designed and constructed. Plans are underway to deploy the coating, where conditions are applicable, throughout the industry.
Tracking Mercury Contaminant in the Subsurface
Authors: Bourdet Julien F. , Stalker Linda , Hortle Allison L. , Ryan Chris G.
Published: November 2020

In 2019, Australia led all Liquified Natural Gas (LNG) exporters in incremental growth (IGU World LNG report, 2019), supported by the start-up of the Wheatstone and Ichthys LNG projects. Production and economic recovery of gas are affected by the association of chemical compounds naturally present at low to trace levels within natural gas such as carbon dioxide, hydrogen sulphide and mercury. These contaminants generate a cascade of costly treatments and waste recovery efforts. If the level of mercury in a produced gas stream is higher than expected, the treatment process in the LNG plant rapidly reaches capacity and may cause shut-down of the facility or rejection of gas supply resulting in significant profitability impacts. There may also be long term consequences that could impact on the decommissioning of industrial infrastructures in the future.

High mercury levels in produced gas have been reported in South East Asia and Australia (Chalkidis et al., 2020; Black and Saunders, 2018; Zeeshan and Manikandan, 2017). However, currently there are no standard method to accurately quantify the presence of mercury in gas in the reservoir. The highly absorbent and multi-speciated nature of mercury makes reliable gas sampling difficult and generally leads to gross under-predictions of quantity. The spatial distribution of mercury within the reservoir means mercury may not appear in the initial production phase and its presence in fluids may vary over the lifetime of the field.

Understanding the source, the transport mechanism and the distribution of naturally present contaminants in the subsurface is critical for lowering their impact in industrial activity through avoidance. High mercury levels of about 1000 microgram per cubic meter (µg/Sm3) were reported in reservoir gas samples from a sand unit of the Gorgon gas field in the Northern Carnarvon Basin, Australia (Chevron Australia, 2014). Other gas samples from different depth intervals in the same well delivered readings below 20 µg/Sm3. The closest exploration well to GOR-1D (about 2.5 km), North Gorgon-1, has provided abundant core materials that were investigated to detect and understand the distribution of mercury in the rocks. Our research seeks to address some of the significant but remaining geoscientific knowledge gaps on the generation and distribution mechanisms of mercury in rocks, from source to accumulation in the subsurface. In this paper, we provide an assessment of the workflow by examining preliminary analytical results on the detection and quantification of mercury in rocks.
Generator in Situ Inspection
Authors: Kutbi Jehad Fawzi , Alkharboush Abdullah Abdulelah , Georgiou Ioannis
Published: November 2020

Assessing power generators condition utilizing periodic inspection programs has been an established practise in power plants with proven reliability and availability results. However, the continuous efforts to reduce maintenance costs while minimizing the outage periods opened the path towards the development of alternative inspection tools and services that facilitate rapid offline assessment of equipment inspection. The conventional technique of pulling out a generator rotor in order to have an access over the stator is time consuming and requires extensive logistic preparation in addition to high exposure risks. Moreover, utilizing an advanced technology tool for online measurements such as robotic devices for In-Situ inspection provide an economical, fast and low risk alternative solutions. Ras Tanura Producing Department (RTPD) from Saudi Aramco has successfully implemented In-Situ inspections for two power generators at one of its plants. This paper compares the conventional rotor out inspection with In-situ technology techniques that allow inspection and testing while the rotor is still installed whereas will highlight a case study in which In-Situ technology was implemented on RTPD generators.
Petrographic Characterization of Black Shales From Belata Formation, Peninsular Malaysia: Implication for Fracability
Authors: Boateng Esther Owusu , Tsegab Haylay , Borecho Cornelius Bavoh
Published: November 2020

Successful fracturing processes in shale, during shale gas drilling and production, is an effective way to reduce environmentally and cost risks. Fracability of rocks is highly affected by the rock’s quartz, carbonate and/or clay content. Thus, a fair understanding of shale quartz, carbonate and/or clay content is critical in achieving an effective fracturing process. The objective of this paper is to qualitatively and semi-quantitatively characterise the quartz and clay minerals within the black shales of the Belata Formation. Twenty-two samples were analysed using Scanning electron microscopy (SEM) fitted with energy dispersive x-ray spectroscopy (EDS) and X-ray diffraction (XRD). The result showed slight variations in the concentrations of quartz, which are not too highly deviated from the recorded average. Chlorite and kaolinite are the dominant clay minerals within the black shales. However, the chlorite and kaolinite in Belata black shale show little effect on the fracability of the shales. The estimated brittle index indicated a high quartz/silica composition in the Belata black shales compared to clay minerals. The brittle index further suggested a high fracability with quartz concentration of about 86 %. The range of fracability using the brittle index method is between 0.91 to 0.64, with an average of 0.79, which is considered very high. Thus, these shales could be fractured at various locations through hydraulic fracturing in order to improve their permeability for any flued within the shale. This finding provides new insight into the fracability of the Paleozoic shales in the Peninsular.
Sand Production Management While Increasing Oil Production of a Gravel Packed Well Equipped with RCP Autonomous Inflow Control Devices in a Thin Heavy Oil Reservoir in Offshore China
Authors: Xiong Shuquan , Li Fan , Wei Congda , Luo Donghong , Moradi Mojtaba
Published: November 2020

In the 2018 infill development campaign, improved production was targeted by the operator through the installation of Autonomous Inflow Control Devices (AICDs) in a horizontal well at Offshore China. However, as the well requires gravel packing to manage the sand, the integration of AICD and gravel pack was an issue. The well was expected to intersect heterogeneous formations with varying properties resulting in an uneven reservoir influx toward the wellbore. In addition, water mobility in the reservoir is at least 150 times bigger than oil mobility and a strong aquifer is located near the well. Therefore, similar to the analogue wells completed with gravel packs, oil production from this well was expected to suffer severely from an early water breakthrough in a couple of weeks. These challenges can be mitigated by deploying AICDs that can manage the reservoir fluid influx toward the wellbore and therefore optimise the well performance. AICD, an active flow control device, delivers a variable flow restriction in response to the properties of the fluid and the rate of flow passing through.

An integrated workflow was followed to deliver successfully the AICD application for CNOOC in an offshore heavy oil reservoir with huge uncertainties in remaining oil thickness and water-oil contacts. The well with the horizontal length of 440m was drilled in a thin formation with the oil column of 4.5m on average. The well intersected three different geological layers with different rock properties. The lower well completions comprised gravel pack, sand screens and RCP AICD valves were connected to an ESP pump lifting the fluids to the surface. The well was segmented in 4 compartments and a tailored AICD completions based on the real-time log data from the well was designed to properly restrict the production of unwanted fluid. Through teamwork between the companies, the well was successfully completed with AICD and gravel pack.

The final modelling was performed just in the time span between reaching target depth and running the completion. Over a period of 12 months production, the offset well with no AICD devices encountered water production in the first two weeks and water cut has kept increasing to 88%. However, the AICD well not only has no problem in terms of sand production and has limited water cut to less than 15% but also has successfully delivered 200% increase in total oil production compared to the offset well.

This well is an example that demonstrates the possibility of a successful combination of AICD and gravel packs. AICD completions ensured a balanced contribution from all reservoir sections and limited water production significantly while gravel pack kept the valves safe from impacts of sands.
Impact of Petrophysical and Geomechanical Modelling on Brittleness Index
Authors: Iqbal Omer , Padmanabhan Eswaran
Published: November 2020

Rock fabric and physical properties are known indicator of the fracturing potential of unconventional reservoirs under hydraulic fracturing stimulation. However, very limited study is documented on reservoir cut offs to find fracturing potential. Therfore, systematic workflow adopted to estimate reservoir properties and their relationship with brittleness index. For this purpose, the One-Dimensional Mechanical Earth Model (MEM) and multi-mineral petrophysical models is developed to estimate reservoir properties based on laboratory experiments and well logs. Rock brittleness (BI_T) is estimated using petrophysical properties and elastic properties. The reservoir cut offs determined to classify reservoir into brittle and ductile zones. The correlations indicated that higher concentration of minerals quartz and siderite, and young's modulus (YM_Cali) enhance brittle nature of rock, while higher concentration of organic richness (TOC), porosity (φT), clay contents, and Poisson's ratio enhance ductile nature of rock. The gamma ray log indicated a decreasing trend with an increase in brittleness index. However, there is no significant relationship observed between BI_T, pore pressure and strength/failure parameters except few zones, where BI_T decrease with an increase in pore pressure that is attributed to higher clay minerals in such zones. There is significant decrease in BI_T observed with an increase in fracturing pressure. It implies that brittle rock requires less fracturing pressure to induce hydraulic fractures or open natural fractures. Both shale formations had an organic richness of 3% to 5%, total porosity, φT, of 5% to 20%, and a BI_T of 0.15 to 0.7. It is observed that calibrated values lied between static and dynamic geomechanical properties, which is considered actual reservoir properties. The stress regime is strike slip due to higher magnitude of maximum horizontal stress (σH). Furthermore, the several correlations could be used to classify reservoir into brittle and ductile zones, which would enable the better selection of intervals for fracturing. The model indicated that the Roseneath shale was potentially better than the Murteree shale for stimulation purposes because of its high BI_T, and favourable stress concentration, which is attributed to its high content of quartz and siderite, and relatively less organic matter. However, generally, both shale formations fall in the region of "less brittle". It is recommended that reservoir properties could be computed from top to bottom of interval by integrating core and well logs data due to good agreement between core and well logs which could be used to assess fracturing potential of reservoir. The reservoir cut offs can be used as a proxy to find fracturing potential in unconvemntional reservoirs.
Challenges in Managing Top of Line Corrosion TLC in Multiphase Wet Gas Pipelines
Authors: Ong Hock Guan , Faziana Sagara , Leow Chun Ho , Lim Gek Joo,
Published: November 2020

Top of Line corrosion (TLC) has becoming a growing concern for the oil and gas industry over the past recent decades especially on the offshore subsea high temperature and high pressure (HTHP) pipelines. This paper will present the challenges in managing TLC in multiphase wet gas pipelines. It will also cover the design, execution, appropriate inspection and corrosion monitoring to ensure pipeline integrity meeting the intended design life. There are many corrosions prediction modelling softwares available in the open market. However, once TLC is predicted in a pipeline, there are only few mitigation options which are by material selection, chemical injection, routine operation pigging, batch inhibition, etc. New projects are often considering material selection to mitigate TLC. This approach is rather straight-forward, however, high CAPEX is required. As for existing pipelines in operation with TLC, it must depend on effective chemical control (corrosion inhibitor) that could protect both TLC and BLC (bottom of line corrosion) coupled with continuous corrosion monitoring tools. Routine pigging during operation and more frequent inspection could be required too. To date, there is no common standard in testing the effectiveness of volatile corrosion inhibitor (VCI) in mitigating TLC.
Uncertainty in Reservoir Fluid Fill Prediction and Its Implications on the Business – Case Studies from South East Asia
Authors: Ali Arfan , Jofri Azimah , Mohd Yakup Mohamad Azwan , Zamikhan Norshah , Chung Shao-Jung
Published: November 2020

LWD logs are becoming increasingly reliable for the primary (and often the only) source of downhole log data. The standard and advanced mud logs in conjunction with LWD logs are used to conclude on the reservoir fluid typing (gas, oil, water) in real time. However, there are examples where the mentioned logs can equally misguide the log interpreter.

An incorrect fluid interpretation can result in huge financial implications. There could be decisions associated with laying new pipelines, upgrading surface facilities (separators, compressors) and/or installing new platforms. In addition, the fluid fill would have a direct impact on the company reserves and reporting.

Historically, a number of exploration and development wells were drilled in the SE Asia region where minimal LWD log data was acquired. This data is often considered sufficient for evaluation of reservoir properties. However, for fluid fill, the data was insufficient for various valid reasons and the initial interpretation from the LWD logs could have led one astray. This paper highlights examples where an integrated effort from the subsurface disciplines provided insights into the misbehaviour of the LWD logs and mud log data.

The examples shown in this paper demonstrate that similar looking reservoir log responses could lead to an uncertain fluid fill. In such circumstances, the requirement for additional log data needs to be highlighted at an early stage of the project and should also be reflected in the well and field economics. The uncertainties in the reservoir fluid fill needs to be reflected in the project risk register and in the field development plan (FDP).

This paper provides alarming signals to the log interpreters that extra caution needs to be taken in log data acquisition, processing and interpretation stages. The paper also highlights the importance of integration between subsurface disciplines and the criticality for the log interpreters to be familiar with the depositional environments. It has also been demonstrated that a limited set of log data could equally mean having no information unless additional evidence is available to address the uncertainties.
Well Integrity Analysis and Risk Assessment for Injection Wells in CO2 Flooding
Authors: Zhang Shaohui , Wang Shuai , Lv Yongke , Pan Ruosheng , Geng Xiaoran , Liu Yang , Bai Mingxing
Published: November 2020

Well integrity risk assessment is of great importance to the safe production in CO2 flooding. In this study, the well integrity of injection well in CO2 flooding is analyzed firstly, and the assessment criteria of injection well integrity are put forward. Secondly, the injection well integrity failure risks are analyzed, and the Bow-tie model of well integrity failure is established. By transforming the Bow-tie model into a hierarchical structure, the weights of well integrity influencing factors are obtained with the use of analytic hierarchy process (AHP). Next, the probability and consequences of each single well integrity risk are assessed by using risk matrix method. Finally, the well integrity risk assessment model of injection wells in CO2 flooding is established, and the well integrity risk value and risk level are calculated.

The injection well integrity assessment of CO2 flooding can be divided into three assessment units: wellhead, pipe string and wellbore. The well integrity influencing factors and assessment criteria involve the following fifteen aspects: christmas tree, wellhead seal, tubing, safety valve, packer, casing, cementing, etc. The probability of well integrity risk and the consequence caused by the risk are both considered in the well integrity risk assessment. Based on the risk assessment results, the injection well integrity risk can be divided into four levels: critical risk, high risk, medium risk and low risk. With the use of the above method, the well integrity of certain CO2 injection well in Jilin oilfield of China has been assessed, and the main risk influencing factors and the risk level of well integrity have been determined.

The well integrity analysis and risk assessment of injection wells in this study provide a reliable basis for safety risk decision making and management, and are helpful to reduce the risk of safety accidents in CO2 flooding.