bluuebunny/crossref_metadata_2025_split huggingface dataset:
Single-Pile Offshore Structures as a Cost-Effective Alternative to Small Fixed Platforms in Shallow Water
Authors: Chatterjee Prabir Kumar 
Published: March 2021

Abstract
The present paper proposes an alternative to small offshore platforms with tripods and four-legged jackets by a single-pile structure for shallow water depths. The pile will be driven into seabed without a jacket and stability of the structure against environmental loads will be ensured by a few tie members connected to seabed with the help of specially-designed small concrete foundations. Tie members will be bolted to both the pile and the foundation. Four different cases of single-pile structures in three different water depths (20.0m, 31.5m and 15.0m) are presented. Omnidirectional waves of 10.0m height along with wind and current are considered in the study. Analytical method is suggested to simulate interaction of concrete foundations with soil that can be easily implemented in structural analysis. Structural design is performed as per API RP 2A working stress design method. The results indicate that the proposed single-pile structures have considerable reserve strength against failure due to extreme environmental loads and impact from medium sized boats.
Operations Readiness and Assurance OR&A on Pipeline Transient Analysis at A Floating Storage & Offloading FSO to Cater for Field-A Gas Production
Authors: Mahmud Nurul Syuhada , Kuanji Jennyfer 
Published: March 2021

Abstract
COMPANY-A is the operator of Field-A gas field that started operation in Country-A in 1996. Reliable and smooth condensate handling is key to ensure the continuous gas production and hence, maintaining the gas supply assurance. To cater for the reduced condensate throughput and export, COMPANY-A hired Company-B to refurbish a Floating Storage and Offloading vessel (FSO) named FSO-B; a new player and has minimum experience in oil and gas industry. Operation readiness review is crucial to ensure the safe operations in Field-A. In this paper, a review on the pipeline transient analysis and process safety focusing on condensate export line from SPM, flexible hose and piping modification on FSO-B is described as a showcase.
The review that referred to API standard and internal PETRONAS Technical Standards (PTS) has contributed in determining the revised operating envelop of the SPM and FSO-B compared to the initial project proposal. The technical operation and design review resulted in the avoidance of potential loss of process containment (LOPC), production deferment and PETRONAS reputation as prominent gas supplier within the region. It is important to ensure that the operating envelop is suitable with the production profile.
With the operational readiness exercises, FSO-B was designed correctly and ensured of safe operation. FSO-B was commissioned on time and started operation without much delay and hence, securing the gas supply of 60 MMSCFD from Field-A to Customer-C, and exporting up to 1500 BPD condensate smoothly without interruption. This exercise has contributed to safeguard the tangible value of maintaining the gas production as well as keeping the intangible value of PETRONAS reputation.
The operational readiness especially on the pipeline transient analysis review is significant novel to be replicated in other similar operations in PETRONAS and in similar operations in other operators.
Multiphase Flow Loop Testing of Autonomous Inflow Control Valve for Light Oil
Authors: Taghavi Soheila , Ismail Ismarullizam Mohd , Aakre Haavard , Mathiesen Vidar 
Published: March 2021

Abstract
To increase the production and recovery of marginal, mature, and challenging oil reservoirs, developing new inflow control technologies is of great importance. In cases where production of surrounding reservoir fluids such as gas and water can cause negative effects on both the total oil recovery and the amounts of energy required to drain the reservoir, the multiphase flow performances of these technologies are of particular significance.
In typical cases, a Long Horizontal Well (LHW) will eventually start producing increasing amounts of these fluids. This will cause the Water Cut (WC) and/or Gas Oil Ratio (GOR) to rise, ultimately forcing the well to be shut down even though there still are considerable amounts of oil left in the reservoir.
In earlier cases, Inflow Control Devices (ICD) and Autonomous Inflow Control Devices (AICD) have proven to limit these challenges and increase the total recovery by balancing the influx along the well and delaying the breakthrough of gas and/or water. The Autonomous Inflow Control Valve (AICV) builds on these same principles, and in addition has the ability to autonomously close when breakthrough of unwanted gas and/or water occurs. This will even out the total drawdown in the well, allowing it to continue producing without the WC and/or GOR reaching inacceptable limits.
As part of the qualification program of the light-oil AICV, extensive flow performance tests have been carried out in a multiphase flow loop test rig. The tests have been performed under realistic reservoir conditions with respect to variables such as pressure and temperature, with model oil, water, and gas at different WC's and GOR's. Conducting these multiphase experiments has been valuable in the process of establishing the AICV's multiphase flow behavior, and the results are presented and discussed in this paper. Single phase performance and a comparison with a conventional ICD are also presented. The results display that the AICV shows significantly better performance than the ICD, both for single and multiphase flow.
A static reservoir modelling method have been used to evaluate the AICV performance in a light-oil reservoir. When compared to a screen-only completion and an ICD completion, the simulation shows that a completion with AICV's will outperform the above-mentioned completions with respect to WC and GOR behavior. A discussion on how this novel AICV can be utilized in marginal, mature, and other challenging reservoirs will be provided in the paper.
Completion Design and Optimization to Assure Flow in Gas Wells Life Cycle
Authors: Mehran Fatemeh 
Published: March 2021

Abstract
There are 26 sedimentary basins in Asia divided into four categories on the basis of hydrocarbon prospectivity. A total of about 3.14 million square kilometres area is covered by these sedimentary basins which includes both onshore and offshore. One of the most prominent category-1 (commercially producing) basin of Asia is XXX basin with an estimated hydrocarbon potential of about 1130 million metric tonnes. It covers an area of 15000 square kilometres onshore and about 25000 square kilometrs offshore, upto a water depth of about 1000 m (National Data Repository, DGH-MoPNG, GOI). It is believed that Asia relies heavily on XXX Basin for its energy security. However, one of the major challenges being faced in the XXX Basin offshore field development is Flow Assurance. Since most of the fields offshore basin are in deepwater setting, high pressure and low temperature conditions aggravate flow assurance problems.
Flow assurance is identified as a significant deepwater offshore development challenges and hence has emerged as a prominent discipline in the oil and gas industry. There are several definitions of Flow Assurance, one of the most common of which is: Flow Assurance is the analysis of thermal, hydraulic and fluid related threats to flow and product quality and their mitigation using equipment, chemicals and procedure (Makogon T.Y., 2019). It can be understood as an all-encompassing holistic approach of fluid flow from the reservoir to point of sale with an integrated perspective of asset development. In simple terms flow assurance aims to ensure fluid flow irrespective of flow trajectory, fluid chemistry and environmental conditions (Brown L.D., 2002). It has become increasingly important in recent times as the industry has turned to deepwater resources for energy sources. There are multiple examples where the proper utilization of Flow Assurance technology has saved billions of dollars for oil and gas companies. Norske Shell saved approximately 30 billion NOK in the Troll field by resorting to direct electrical heating of produced fluids. The same was utilized by Italian company ENI for its Goliath development and by BP in its Skarv field (Makogon T.Y., 2019).
This paper describes a comprehensive workflow to identify and mitigate flow assurance risks for the deepwater block in XXX Basin.
Making Things Right in Development and Management of Highly Contaminated Giant Carbonate Gas Field and Returning the CO2 to Subsurface Sequestration
Authors: Tewari Raj Deo , Sedaralit Mohd Faizal 
Published: March 2021

AbstractNatural gas is the noble fuel of 21st century. Consumption increased nearly 30% in last decade. Exploitation of conventional, unconventional, and contaminated gas resources are in focus to meet the demand. There are number of giant gas fields discovered worldwide and some of them with higher degree of contaminants viz. CO2, H2S and Hg. Additionally, they have operating challenges of high pressure and temperature. It becomes more complex when discovery is in offshore environment. This study presents the development and production, separation, transportation and identification & evaluation of storage sites and sequestration and MMV plan of a giant carbonate gas field in offshore Malaysia.Geological, Geophysical and petrophysical data used to describe the reservoir architecture, property distribution and spatial variation in more than 1000m thick gas bearing formation. Laboratory studies carried out to generate the rock and fluid representative SCAL (G-W), EOS and Supercritical CO2-brine relative permeability, geomechanics and geochemical data for recovery and storage estimates in simulation model and evaluating the post storage scenario. These data are critical in hydrocarbon gas prediction and firming up the number of development wells and in the simulation of CO2 storage depleted carbonate gas field. Important is to understand the mechanism in the target field for storage capacity, types of storage- structural and stratigraphic trapping, solubility trapping, residual trapping and mineral trapping. Study covers methodologies developed for minimization of hydrocarbon loss during contaminants separation and utilization of CO2 in usable products. Uncertainty and risk analysis have been carried out to have range of solution for production prediction and CO2 storage.Coupled Simulation studies predict the production plateau rate and 5 Tscf recovery separated contaminants profile and volume &gt; one Tscf in order to have suitable geological structure for storage safely forever. Major uncertainties in the dynamic and coupled geomechanical-geochemical dynamic model has been captured and P90, P50, P10 forecast and storage rates and volumes have been calculated. Results includes advance methodologies of separation of hydrocarbon gas and CO2 like membrane and cryogenics for bulk separation of CO2 from raw gas and its transportation in liquid and supercritical form for storage. Study estimates components of sequestration mechanism, effect of heterogeneity on transport in porous media and height of stored CO2 in depleted reservoir and migration of plume vertically and horizontally. Generation of chemical product using separated CO2 for industrial use is highlighted.
Drilling Across a Highly Unstable Zone in an Exploratory Well in South Mexico
Authors: Cardenas Miguel Angel , Martinez Araceli , Hernandez Marce , Luna Octavio , Cano Ramon , Rodriguez Efrain 
Published: March 2021

Abstract
The Comalcalco Fault is a regional discontinuity that can present highly unstable zones when crossing it or its influence zone. This instability can lead to notorious increase in drag forces, cavings, stuck pipe events and ultimately loss of sections or the well. In the 12 ¼" hole of this exploratory well, this fault was present and despite some of the wells in the field managed to cross it without consequences, the influence was more notorious, and the problems lead to catastrophic results.
While drilling the 12 ¼" section, the team was able to drill up to 4368 m without any relevant problems. The fault was intersected and drilled pass to section TD with the previous casing shoe at 2966 m. However, when a trip to surface was necessary, abnormal drag forces that avoided further movement of the string were experienced. This event led to the loss of the section and the need to perform a sidetrack, right across the influence zone of the fault at 3200 m.
The risk was reassessed, and numerous preventive and mitigation measures were put in place, including drilling the section with a 12 ¼" pilot bit, enlarging the pilot hole to 13 ½" to cover the influence zone and having a contingency plan to run the 11 ¾" liner. Additionally, the formations were reinforced through drilling fluids design, and drilling and tripping strategies were optimized to minimize zonal invasion and influence zone disturbances that could lead to additional cavings.
After the successful sidetrack, the section was drilled to 3600 m, 200 m below the fault’s influence zone. Good ROPs and low levels of stick and slip were observed despite several reaming runs while drilling. The contingency liner was run to TD, achieving the objective of isolating the influence zone of the Comalcalco Fault. With the problematic zone placed behind pipes, drilling the remaining of the original 12 ¼" sections with a 10 5/8" × 12 ¼" reamer resulted in the longest and fastest enlarged section to be realized in the field. With all the preventive measures put in place, the original 9 5/8" casing was set at its planned depth, avoiding an additional casing string and a change of the design of the completion.
Engineered High-Performance Lightweight Thixotropic Lost Circulation Solution for Vugular and Natural Fractured Formations UAE Case History
Authors: Phyoe Thein Zaw , Salazar Jose , Albuja Eduardo Herrera , Kapoor Saurabh , Orfali Mohd Waheed , Kondo Kazuyoshi , Sajid Muhammad , Rahhal Gilbert 
Published: March 2021

Abstract
Lost circulation while drilling across vugular or naturally fractured formations is a difficult challenge which will come with high cost for the oil and gas industry. When lost circulation encounter, the drilling company will result in nonproductive time and remedial operational expenses. Most of the fields in UAE are encountering lost circulation problems while drilling across surface sections, which are difficult to control with conventional lost circulation solutions. Newly engineered high-performance lightweight thixotropic proves beneficial to control losses in vugular and natural fractured formations. The main challenge while drilling the surface section in one UAE field is the total loss of returns and flowing formation. This leads to the inability to continue drilling due logistics to continue producing drilling fluid and to keep the well under control and risk of stuck pipe due to poor cuttings removal. Conventional low-density cement slurries have been widely used to cure losses while drilling, but with low effectiveness. A new lost circulation solution that combines lightweight (10.5–lbm/galUS) high-performance cement and a thixotropic agent produce an engineered high-performance lightweight thixotropic lost circulation solution with fast gel strength and improved compressive strength, enabling the plugging of large voids and fractures to recovery wellbore integrity required to continue drilling.
Extensive laboratory qualification tests were performed for static gel strength development to confirm the plugging efficiency and compressive strength development. The results were promising with more than 110 lbf/100 ft2 of static gel strength in 10 minutes and compressive strength development of 1,000 psi within 24 hours at low surface temperature. In addition, a transition time (TT) with on-off-on test demonstrated more faster gel strength development was developed when the reduction of the shear rate and regained pumpable with reapplication of shear. In one of the wells, total losses were encountered while drilling across surface section. The lightweight high-performance thixotropic solution was pumped for the first time worldwide, proved that the innovative lost circulation solution was effective in curing the losses, and enabled the operator to continue drilling the section to TD.
This case study demonstrates that the engineered system is effective in curing losses and reducing nonproductive time. The unique properties of more faster gel strength and enhanced compressive strength make this system more effective for treating a different types of lost circulation scenarios during drilling (Jadhav and Patil, 2018). New high-performance lightweight thixotropic cement lost circulation solution exhibits strong performance in curing total losses and establishing well integrity with reliability.
Light Weight Cement Slurry Tailored With Suspended Beads For Optimum Isolation of Highly Depleted Reservoirs in Offshore Malaysia: A Case Study
Authors: Patil Mayank , Annamalai Ramesh , Tan Brendon , Kumar Avinash Kishore , Lau Chee Hen , Bin Saari Muhammad Syazwan 
Published: March 2021

Abstract
Hollow-glass microspheres (beads) are widely used to generate light weight cement slurries for cementing across highly depleted zones and weaker formations; this paper discusses tailoring of a cement slurry and the execution of cementing operations for the successful deployment of an innovative liquid bead solution instead of the conventionally blended beads to achieve zonal isolation for a development well in Malaysia.
Usage of dry bulk blended beads poses many challenges, such as rig and vessel silo management, quality control of beads, multiple blends on the rig and excess back-up blends. A new approach has been proposed using a liquid bead system to produce a light weight cement slurry by adding beads stabilized within a suspension fluid as another liquid additive to help eliminate the need of dry bulk blending of beads and at the same time accomplishing all the obligatory cement properties for a production casing section in depleted zones.
A successful offshore application of liquid beads was executed in a production casing, meeting all the necessary property requirements for cementing in a depleted zone. The cement slurry was developed in a local field laboratory with standard laboratory testing techniques and equipment. Liquid beads can be added to the cement slurry using liquid additive pumps or batch mixed on the surface. Considering the slurry volume of the production section and the importance of a homogeneous cement slurry, liquid beads were injected into the recirculating line of the cement batch mixer. A yard trial was performed prior to the actual job which validated the easy transfer of liquid beads. Relative to the conventional dry-blended approach, this economically more efficient liquid bead cement system was easy to mix and achieved the required design density without any operational issues. The cementing operation was executed with full returns throughout the job at maximum planned displacement rates. To evaluate cement placement, a post job analysis was performed.
The first application of this liquid bead technology in Malaysia was to generate a light-weight cement slurry and was successfully implemented for a 9-5/8" production casing where 167 bbl of the liquid bead base cement slurry was mixed, pumped & effectively placed.
Progressive Cavity Pump Self Optimising System Argentina Field
Authors: Iguaran Marco , Suarez Leonardo , Paz Juan , Altube Martin , Nicoletti Ariel , Bustamante Mario 
Published: March 2021

Abstract
One of the greatest challenges for wells using an artificial lift system (ALS) is the ability to optimize production while minimizing expenditure. This process involves a perfect balance between effective oil production management, extending ALS longevity, and ensuring energy efficiency, to produce the lowest operational cost. In oil fields under secondary recovery and mature or depleting conditions, production optimization involves continuous monitoring and surveillance of operational variables affecting changes in flow rates caused by surface and subsurface conditions, such as water injection, pressures, obstructions, etc. To achieve the desired goal of a properly optimized process, strong technical expertise is required almost continuously. Based on years of experience in ALS monitoring, surveillance and optimization, various tools and software have been developed to assist in parameter monitoring.
Traditionally, the well optimization of progressive cavity pumps (PCP's) is completed on a daily or weekly basis through the analysis of continuous monitoring and surveillance data by a technical expert. As an alternative, downhole (DH) gauges have been installed to directly measure the exploitation conditions, however, such gauges can be costly relative to the production lifting method. To improve the process, well optimization control units have been produced to maximize oil production using algorithms. These systems take advantage of surface variables such as velocity, current, torque, flow rate, and wellhead and casing pressures to respond to changes in operational conditions, ensuring maximum system uptime and reducing intervention costs by increasing the mean runtime between failures.
This paper will focus on the well monitoring and optimization system implemented in a YPF well in Neuquen, Argentina. The theoretical bases, concerns, benefits and results will be discussed throughout. The evaluated well used a surface flow meter to allow the system to converge to an optimal flow rate by changing velocity while considering system performance in terms of submergence, torque, current, and wear between the tubing and rod string at high operating speeds. Post-implementation, by optimizing the flow rate, the oil production doubled while reducing the manhours required, ultimately increasing profit while reducing operational costs.
The results of implementing this well monitoring and optimization system have been validated through field trial, creating a trusted method to extend throughout Argentina fields and aiding production engineers in their optimization targets.