bluuebunny/crossref_metadata_2025 huggingface dataset:
Thailand’s First Green Power Technology Playground in Energy Transition Era for Net Zero Target
Authors: Pechvijitra Pimpisa , Thamma Thammasak , Jaiyen Jutiporn , Onsuratoom Surakerk , Rewlertsirikul Piyanee , Anantasate Sumeth
Published: February 2023

"Green Power Technology Playground" (GPTP) is the first demonstration project in Thailand where the whole integration system for green power technologies, ecosystem, and Internet of Things network are combined. This project is located at Eastern Economic Corridor of Innovation area (EECi) in Rayong, Thailand. The prominent concept of GPTP is Plug & Play where anyone is welcome to play, learn, and become familiar with new green power technology applications. Thus, every equipment is designed as a small, movable size in a container. It can be easily removed and installed, allowing us to learn and develop innovation for a green power ecosystem.

GPTP is designed to establish the ecosystem of green energy technology. Thus, it is split into seven sections as follows:Green Power Supply: Solar roads and novel generations of solar PVs have been built and provisional areas for future renewable sources are provided.Green Power Storage and Conversion: Advanced, innovative types of battery and electrolyzer are located and green electricity is stored in batteries for the further use in nearby buildings and converted into hydrogen for other applications by the electrolyzers.Green Power Applications: Cutting-edge applications for potential commercialization to new business are provided.H2 Storage: Hydrogen is stored for the further use.Green Backup Power: New generations of fuel cells are provided.H2 Utilization and Carbon Capture Utilization: The plug and play modules for ammonia and urea production and CO2 refrigeration packages are assembled.Smart Energy Management System: By using Internet of Things, all elements in the playground are controlled via cloud. Thus, any related party can access information and monitor the system from anywhere and anytime.

As PTTEP (Main Stakeholder) intends to build innovations for new energy technologies and scale them up for commercialization, the investment in a demonstration project is needed. Investing in a large scale, not know-how, less matured green power technology applications can impose a high risk. Thereby, GPTP will accelerate this step by developing staff’s competency and resource capability. Thus, the main stakeholder can learn how to produce and operate from a small module and quickly scale up for commercialization.
Evaluation of Flow Diverter Chemical to Improve Waterflood Performance as Conformance Control for Heterogeneous Reservoir and High-Temperature Field Application: An Innovative Experimental Design
Authors: Zulkifli Nazliah Nazma , Hendraningrat Luky , Razali Norzafirah , Bakri Che Nasser , Zainal Suzalina , Kechut Nor Idah
Published: February 2023

Water injection fields account for over half of Malaysia’s oil production, with most of these fields at matured waterflooding stage. Low sweep efficiency due to water conformance where reservoir with high heterogeneity might cause premature breakthrough is one of the issues that leads to low oil recovery. In this study, we described the comprehensive experimental analysis to substantiate waterflooding performance in heterogeneous reservoirs by evaluating the flow diversion chemical (FDC) as a water conformance agent at high temperature.

Chemical characterization, rheology, particle size analysis, compatibility, and thermal stability were evaluated for FDC according to the prevailing mechanism. Afterward, an experiment to simulate the reservoir environment was conducted to estimate oil incremental and blocking mechanism, in terms of residual resistance factor (RRF) performance in the intended field condition.

The test was innovatively set up using commercial outcrop and reservoir native cores in dual-core permeability systems to test high permeability and low permeability porous media at high temperature up to 115°C temperature to mimic the conformance process. Typical single core flooding test are only able to determine the potential of the blockage mechanism by determining the RRF, without the diversion effect to quantify the additional oil recovery from the flow diversion process. The setup uses cylindrical preserved core plug samples with permeability contrast ranges from 100mD to 2 Darcy and tested at 115°C. The customized coreflood design successfully mimicked the conformance process. In our study, the RRF of 186 and cumulative oil recovery of 52% with an incremental oil recovery of >5% was obtained by the FDC injection.

The study provides an innovative way in the coreflooding experiment to evaluate the performance of a conformance control agent in a heterogeneous reservoir with high temperatures.
Application of Simulation Software to Enhance Filter Cake Breaker Placement
Authors: Govinathan Kesavan , Jain Samyak , Balasandran Anandhadhasan , Yeo Kim Teng
Published: February 2023

Placement of a delayed filter cake breaker fluid system is usually carried out during the lower completion phase of a well development. Whilst the fluid system would undergo extensive testing during its design phase, the objective of achieving a good clean-up of the target interval requires both testing and an optimum placement strategy. A good clean-up improves the possibility of achieving the desired production rates when the well is put on production.

Placement of the treatment should always be performed below the fracture pressure. If that limit is breached during pumping of the treatment, it can induce losses which would likely result in poor and non-uniform breaker placement and potentially a well control issue. Detailed pre job design and planning using a sand control simulation software allows improved insight and precision to the placement strategy. It also facilitates a better understanding of the completion optimizations that can be incorporated prior to the breaker treatment. This allows the treatment to be kept below fracture pressure and control the losses to the formation.

The use of the software for this application was found to be very effective to optimize pumping rates and manage dynamic pressure limitations using well and completion data. The simulation software was utilized to evaluate multiple scenarios with variable input parameters and the results were analyzed to provide valuable insight into the impact this has on the pumping pressure and equivalent circulating density (ECD) margins.

The paper presents examples of how the breaker treatment design strategy was optimized using the simulation software. Comparison of the modelled and actual data is presented to confirm accuracy and demonstrate how the model can be used to further optimize the design for future operations.
A Successful Field Trial of a New ASP Technology in a High Water Cut and High Recovery Degree Reservoir After Polymer Flooding in North China
Authors: Wu Xingcai , Zhu Yan , Liu Xiaoying , Zhang Song , Gao Shang , He Jingang , Wu Hao , Wang Chunyao , Ye Yinzhu , Cui Guoyou , Lu Qiong
Published: February 2023

Large scale polymer flooding in Daqing Oilfield achieved great success. The average recovery degree of these oilfields after polymer flooding has reached 52.5%, and the average water cut has reached 96.0%. It is urgent to find an effective technical method for further EOR. Targeting the highly dispersed remaining oil in the post polymer flooding reservoirs, the continuous phase polymer solution in ASP technology was replaced by nano-micron particle polymer dispersion to realize optimization for EOR mechanism, so the ASP technology was upgraded. The field test, has been completed the slug injection, and achieved obvious EOR effect.

The ASP slug design with HPAM solution as the main displacement phase was abandoned. A type of water dispersion of nano-micron particle polymer as the main displacement phase was designed to replace the "P" in traditional ASP slug, so that the flowing control mechanism of "P" was optimized. Through synchronous diversion and displacement, it can initiate and sweep the remaining oil dispersed in relatively small pores. A large three-dimensional physical model with the size of 60 × 45 × 4.5cm was made to simulate the real development history of water injection and polymer flooding of the reservoir, based on which, the performance of the upgraded ASP was modeled. Furthermore, the program was designed and optimized by numerical simulation.

The physical simulation fitting experiment of the development history of water flooding and polymer flooding shows that the coincidence rate is 93%+. After polymer flooding, the upgraded ASP further improved the recovery by 15.2 percent. The optimized scheme of numerical simulation is to inject 0.5PV of new ASP slug. Under the precondition of the historical recovery degree of 55.8% and water cut of 98.44%, the new ASP is expected to improve the recovery by 7.9% within 10 years. At present, the field test of ASP slug injection has just been completed, and remarkable results have been achieved, The daily oil production has increased by 60%, and the water oil ratio has decreased from 61.9 to 38.4. The daily oil production of some producers has increased by 2 to 3 times, and the recovery has increased by 5.2%.

The field trial proves that the oil displacement mechanism of nano-micron-particle-polymer ASP flooding chemical system is more advanced and the displacement efficiency is higher than that of the traditional ASP flooding, and the oil recovery can be further enhanced for similar reservoirs under extreme conditions after polymer flooding. The traditional ASP technology is expected to have great upgrading and developing.
Insights from Application of Elastic Full Wave-Field Inversion in Clastic and Sub-Salt Settings.
Authors: Routh Partha , Baumstein Anatoly , Cha Young Ho , Nayak Soumya , Wang Haiyang , Tang David , Barr Jay , Martinez Alex
Published: February 2023

Elastic Full wave-field (eFWI) inversion is aimed at inferring physical properties of the subsurface directly from seismic data. Goal is use highest level of physics to produce reliable properties to impact upstream business decisions. We focus on elastic parameters particularly the ratio between pressure (P) and shear (S) wave velocity, Vp/Vs that can be indicative of the type of fluid present in subsurface reservoir and P-wave impedance, Ip to impact porosity estimation.

Our eFWI methodology derives the wavelet directly from seismic shots rather than using well information. Using field examples we explain the eFWI workflow, outline key steps and provide analysis of the results. The first field example is from a structurally simple clastic setting. The second field example is from a complex sub-salt environment and is focused on differentiating net versus non-net in pre-salt carbonate reservoirs - a challenging problem when using narrow azimuth streamer data. The third field example is from a clastic setting and uses well information to scale the wavelet and is applicable in development and production settings.

Our experiments with the two exploration style field examples show that it is possible to directly invert shot data to obtain geologically meaningful elastic properties useful in exploration and early development phases. However, challenges remain. The inverted Ip has higher fidelity compared to the Vp/Vs ratio. In fact, Ip is sufficiently accurate to be reliably used for porosity prediction. The eFWI Vp/Vs inversion results are only in qualitative agreement with well information (as a blind test) for the clastic example, but sufficient to discriminate the net versus non-net for the pre-salt example. A qualitative match may be insufficient to determine fluid type via rock property inversion without any well control. In an environment without well control, further research is needed to investigate the sensitivity of Vp/Vs and determine if data quality is a key factor, in addition to stabilizing the extraction of elastic parameters in a multi-parameter inverse problem.

The novel aspect for our approach is in developing a practical eFWI methodology in 3D and working with raw seismic shots with very minimal processing. Examples from different geological settings and use of well versus no-well provide valuable insights into current application space and potential research direction on improvements to eFWI algorithm.
Success Story of the Development of Extremely Low-BTU Flare Tip Technology
Authors: Assavanives Boonyakorn , Watanakun Kantkanit , Amarutanon Nunthachai , Kodesh Zach , Muangsuankwan Natthasart , Watcharasing Sunisa , Sinthavarayan Kanokporn
Published: February 2023

Current low-BTU flare tip technologies require a flare gas lower heating value (LHV) of approximately 200 BTU/scf while significant advancement on CO2 removal membrane technology has resulted in an extremely low-BTU waste gases having LHVs around 140 BTU/scf. This requires the extremely lean waste gas to be supplemented with methane to raise its heating value to achieve stable combustion. Not only does the operator lose the benefit of the advanced membrane technology but they also lose product (sellable gas) and have increased green house gas (GHG) emissions at the production site. Consequently, the development of the "Extremely Low-BTU Flare Tip" is beneficial in multiple ways. The Extremely Low-BTU Flare Tip development project was launched as a joint research and development project between PTTEP and John Zink Hamworthy Combustion (JZHC). The innovative design is based on theories behind low heating value gas combustion and improves upon existing low-BTU flare technology. The goal was to obtain flame stability and safe operation in offshore oil and gas production environments at LHVs significantly lower than 200 BTU/scf. This project included multiple iterations of prototype design, simulation, and testing, with various parameter adjustments to optimize the performance against completeness of combustion criteria. The design was studied through computational fluid dynamics (CFD) simulation and prototype testing to develop the operating envelope of the Extremely Low-BTU Flare Tip. The design of the tip integrates John Zink's existing technology with additional components i.e. spokes and top hat. CFD simulation was performed to observe the fluid behaviors, including temperature, velocity, and unburned hydrocarbon; allowing modification of the design prior to the fabrication of the prototype. The final design has been proven by a series of prototype tests to reinforce the level of confidence in its performance and mechanical integrity. The test results show that the Extremely Low BTU Flare Tip has the capability to combust flare gases with an LHV as low as 110 Btu/scf which is a significant improvement over existing flare tip technology. The benefit of this technology is estimated to be between 10-31 MMUSD per year per platform, depending on the lowest achieved heating value. The success of the Extremely Low BTU flare tip development project provides a breakthrough technology which is not limited to brownfield applications but also supports future acquisition and development of Greenfield sites. This Extremely Low BTU flare tip technology will improve the probability of success for greenfield development with a high CO2 reservoir by maximizing reservoir recovery, optimizing overall capital and operational expenditure, and minimizing hydrocarbons flared which has the direct effect of increasing gas sales and decreasing greenhouse gas emissions.
Forecasting Energy Demand and CO2 Emissions for Crude Extraction and Separation Using Machine Learning
Authors: Abbas Muhammad , Naeem Omar
Published: February 2023

With the drop of oil reservoirs’ natural pressure, and injection of higher amounts of water, predicting energy consumption required to extract multiphase hydrocarbon product, and separate it into crude, gas, and water has become a challenging and more dynamic problem. This paper discusses a detailed technique to forecast energy demand for water injection and Gas-Oil Separation Plant (GOSP). Key elements of the method include identifying the energy, products, and feed streams, along with other parameters impacting the energy demand. The relationships among all independent and dependent variables are identified, along with the consideration of ambient conditions and equipment operating efficiencies. Machine Learning (ML) algorithms are then applied, using available industry software, to build and improve these relationships using the historical data. The best-fit forecast models, also called champion models, are selected that provide the least variance from actual data. These models can be updated, using the software, as the new data is received and variance between predicted and actual energy increases. The forecasted energy demand is converted to CO2 emissions using the conversion factors for fuel gas and power. The forecasting results and underlying process can be converted into dashboards for visualization and utilization by the users of operating plants. The method described in the paper is novel and first of a kind for predicting energy demand and CO2 emissions for a GOSP considering increases in water cut and water-injection.
Encapsulated ESP System: An Innovative Solution for Extended Run Life in High H2S Environments
Authors: Alghamdi Anwar S.
Published: February 2023

The electric submersible pump (ESP) is one of the most reliable artificial lift methods for delivering high flow rates in oil wells. If well designed for reservoir properties, ESPs may run for several years before failing. Despite many ESP design advancements, electrical connections remain within the most prominent points of failure in high H2S environments. This paper presents an innovative approach to mitigate electrical connection failures by encapsulating the ESP system for extended ESP run life in high H2S environments.

Following an ESP design review to explore current practices in mitigating ESP electrical-connection failures in sour wells, an innovative ESP system was designed to eliminate electrical-connections’ contact with well fluid. The ESP is connected from the top to a production tubing, encapsulated within a pressure-retaining pod, and located above a deeply set production packer. The motor head is designed to partially set outside the pod to accommodate electrical-cable connection, while partially encapsulated within the pod to deliver the necessary electrical supply to the ESP motor. The tubing-casing annulus (TCA) is then filled with inhibited-brine to protect the electrical connections.

Experts in the field typically select special ESP metallurgy and electrical connections (i.e., metal to metal) in high H2S wells to extend the run life of ESP systems. Although the development of multiple versions of electrical connections can mitigate H2S attacks, field experience has shown progress in sour environments where ESP run life is not yet matching mild environments. Most efforts were made to minimize H2S attacks on ESP electrical-connections by developing robust ESP systems, but little to no effort was made to eliminate the risk. This challenge can be undertaken by encapsulating the ESP system to avert electrical connection contact with well fluid. Thus, it provided a radical solution to one of the most common ESP failure points in sour environments.

The encapsulated ESP system is a new concept, for which a patent is pending, designed to address electrical connection failures for an extended run life in high H2S environments. This paper will discuss the background and design of the system and its potential to eliminate electrical connection integrity issues.
Analysis of Circulating Pressure and Temperature using Drilling Microchips
Authors: Li Bodong , Zhan Guodong , Okot Michael , Dokhani Vahid
Published: February 2023

Accurate knowledge of circulating pressure and temperature is essential for making critical decisions while drilling operation. Through implementation of miniaturized semiconductor technology, we obtained near real-time dynamic pressure and temperature profile of the wellbore, making previously simulated critical operational data such as equivalent circulation density (ECD) and wellbore thermal distribution now measurable using drilling microchip. The application of drilling microchips to collect distributed pressure and temperature data while drilling is investigated, where each microchip measures both pressure and temperature simultaneously. This study also presents a revised method to calibrate measurements of drilling microchip with depth.

Four field trials were attempted in a slightly inclined well using water-based or oil-based muds, where 10 drilling microchips were deployed in each trial. The recovered data from the drilling microchips are first downloaded and compiled. An in-house software is developed to process and convert time-scale of each drilling microchip to depth considering slippage of drilling microchips in drill string and annulus. An iterative algorithm is designed to calibrate the predicted arrival time with the actual arrival time of each tracer, which ultimately yields the true velocity of tracers in flow conduits. The maximum measured pressure is used as an indicator to locate each tracer at the bottom hole. It is realized that a plateau of pressure versus time can signify a trapped tracer in the flow path if the pump rate was maintained constant.

The results of field trials show that some of the tracers were trapped for few minutes in the lower section of annular space or before the bit nozzle. The results of temperature profiles conclude a unique pattern for almost all of the deployed drilling microchips. However, the results of pressure profiles can be classified in two different groups as drilling microchips could have moved in different batches while pumping. The calculated temperature gradients show a heating zone near the bottom hole and continuous cooling of drilling fluid as tracers move toward the surface. The average pressure gradient is in the range of 0.52 – 0.61 psi/ft among different trials. It is shown that the velocity of tracers in each interval strongly depends on the flow regime.

To our best knowledge, a combined measurement of circulating temperature and pressure using drilling microchips for the first-time is successfully conducted in these field trials. The results can be used for calculation of ECD and temperature profiles, which provide near real-time downhole data for monitoring and diagnostic applications. The measured pressure data also provide new insights about tracking of drilling microchips in the wellbore.
How Expandable Casing Patches Can Restore Casing Integrity and Enable the Sidetracking of an Old Well
Authors: Shahreyar Rehan , Kelly Mitchell , Albouy Charles , Saltel Benjamin , Le Pouezard Benjamin
Published: February 2023

This paper describes how an operator restored the casing integrity of a nonproducing well to resume offshore drilling operations by installing four 10¾-in. overlapping expandable steel patches.

From 2020 to 2022, the operator scheduled a sidetrack drilling program, Māui A Crestal Infill (MACI), from the Māui A offshore platform, located in the Taranaki Basin of New Zealand. The operations included eight wells targeting the remaining unswept zones within the Māui A structure. During a reentry in a plugged and abandoned well, MA-03, a multifinger caliper log and a failed pressure test indicated a casing leak in the 10¾-in. intermediate casing. The log identified severe longitudinal casing wear with some fully penetrating holes. This lack of integrity prevented the scheduled operations from being performed.

Several lost circulation material (LCM) and cement squeeze jobs attempted to seal off the leak but were unsuccessful. A service company proposed a mechanical repair solution to cover the long interval with four 13-m- (42.7-ft)-long customized, overlapping patches. Later, a second caliper was run to check if the cement squeeze jobs had reinforced the area for better patch support. Surprisingly, the zone appeared significantly more damaged, with a complete circumferential casing breach. Thus, the planned solution looked very challenging to implement.

A video camera run, additional thinking, modeling, and cooperative engineering led to a complete redesign of the solution. The lengths and positions of the patches were changed, and one of the patches was assigned to serve as an inner reinforcement.

The team assembled, deployed, and installed the patches in an accelerated mode. In 10 days, the casing integrity was fully restored, enabling the 8½-in. sidetrack hole to be drilled to total depth.

This case is a typical example of how industry practices should evolve regarding the management of casing integrity issues. Remedial cement squeezes are often prioritized over mechanical options, even though mechanical options are now adjustable, much quicker to implement, and likely offer greater success rates.
World's First Advanced Dual ESP System Deployment for Harsh Environment
Authors: Aldossary Abdulrahman Theeb , Partadiwirya Rusam , Subijanto Riza Tjahyadi , Mahmoud Akram
Published: February 2023

A Dual ESP system is a redundant ESP concept that provides backup ESP system to be put on stream immediately if the primary ESP fails, which minimizes workover ESP replacement requirements and cost. An enhanced Dual ESP system for a harsh environment is installed to prolong ESP run life. These harsh environment Dual ESP system are equipped with full Metal-to-Metal Motor Lead Extension as well as H2S Scavenger seal sections on both upper and lower pumps to enhance their durability. Moreover, auto-check valves are included in the system to enhance dual ESP daily operation and maintenance. This paper will share the new dual ESP system design for harsh environments, enhancements, and successful applications in offshore fields.

Two identical, complete, and independent ESP systems are installed with standard Y-Tool (bypass system). All if which was achieved by installing the Metal-to-Metal Motor Lead Extension (MLE) Dual ESP application which acts as backup ESP system to be put on stream immediately after the primary ESP fails. Thus, avails the well potential and postpones the requirement of workover rig mobilization to replace failed ESP. Backup dual-ESP system extend overall ESP system run life in areas with limited rig availability.

The cutting-edge technologies that were deployed in this completion include:

Metal to Metal MLE on both lower and upper ESPs, which proved the increase in the run life compared to the standard MLE. Severe Service Seals (H2S Scavenger Seals), which protects the motor from corrosive subsurface elements. Dual Y-Tools to allow reservoir intervention below the ESP through bypass for logging, acid job and any Wireline / Coil Tubing jobs needed. Non-Return Valve (NRV) which facilitate auto switching between the upper and lower ESPs eliminating the costly offshore barge and wireline conventionally required to install isolation sleeves and blanking plugs. Dual penetration bore Aflas Packer which allows using two cable penetrators and has an Aflas material for sour applications.

This paper will provide in-depth information about each of the cutting-edge technologies deployed in this completion along with the added technical value of utilization. It will further provide the estimated significant cost avoidance achieved in offshore ESP fields following the deployment of this completion.
Fracture Characterisation and Basement Reservoir Potential of Phra Wihan Formation in Southern Part of Uttaradit Province, Northern Thailand
Authors: Piewmoh Watcharapong , Kanjanapayont Pitsanupong
Published: February 2023

This research describes the characterization of fractures in the Mesozoic sandstones Phra Wihan Formation exposed at the southern part of Uttaradit province, Northern Thailand. Fracture characterization of outcrop analog is important to determine potential of subsurface reservoir. The methodology using field study and petrography analysis to determine the relationship of fractures and other structures such as bedding plane and fold geometry. In addition, microstructure analysis can be analoged to the potential of reservoir. The Phra Wihan Formation composed of thick quartz arenite sandstone laminated with mudstones. The structural architectures in study area are remarked by two open fracture sets with orthogonal relationship dominated in the fold limb. The first Set I, subdivided into Set Ia and Set Ib, developed in WNW-ESE direction perpendicular to the fold axial plane and parallel to the major compression stress. The second Set II, subdivided into Set IIa and Set IIb, developed in NNE-SSW direction parallel to the fold axial plane. These fractures imply to be associated with folding stage related to WNW-ESE compression stress during India-Eurasia collision.
Uplifting the Productivity of a Mature Gas Giant in Pakistan Using Integrated Asset Modelling
Authors: Ahmed Sheraz , Muhammad Waqas Ghulam , Sheikh Hafiz Mustafa Ud Din
Published: February 2023

It's almost certain that the oil & gas industry has passed its plateau for large field discoveries. This places an extra burden on the efficient handling of our mature assets, as reasonable amount of hydrocarbon still exists in such reservoirs. However, the ever-increasing cost of new projects and low production gains hardly justify the economics. This study presents a novel approach applied on a mature gas giant, in order to revitalize old wells, optimize surface network and exploit the scattered sweet spots still prevailing in the field, with integrated surface and subsurface engineering strategies.

The field under study has been producing since 1955, with around 112 wells, completed in four independent formations. The primary reservoir (Reservoir-A) is categorized as a depletion-drive gas reservoir and has been on production since the field's inception; the reservoir pressure has depleted from 1,900psi to 300psi. The other formations: Reservoir B, C & D started producing from 1968, 2000 and 2015 respectively. At its peak, the field produced ~1,000 MMscfd gas; but lately, the production decline rose to around 7-8% annually, mainly due to natural depletion. However, deterioration in well performances and limitations of surface facilities (feederlines, Gas-Gathering-Mains (GGMs) and compressors) have also exacerbated this decline, due to the additional pressure drops amassed in their flow dynamics with reservoir pressure depletion & water production.

To counter the field's rapid production decline, a comprehensive workflow and an Integrated Asset model was developed, with an absolute focus on the NPV for each development. At the subsurface level, Reservoir-B (still under-developed) was the first targeted, as most of its wells were producing at uneconomical rates. An ant-tracking algorithm was run on the newly acquired 3D-seismic; and natural fractures - near the 02 high producers in Reservoir-B, were analyzed. A workflow was then developed to target similar fractures and the integrated impact, on surface facilities, was evaluated. Finally, three successful pilots were drilled in Reservoir-B and Reservoir-C, to evaluate the post-drill dynamics. Based on the real-time performances of these pilots with existing producers and surface facilities, the integrated field model was updated, coupling the wells, surface facilities and all four reservoirs (with independent reservoir models). As a result of this integrated model, 12 more wells, 09 workovers, 02 GGM optimizations and 03 compressor modification jobs were finalized; giving an overall increase in EUR by 800 BCF, while the NPV of the field increased by 131 MM$.

This study offers an innovative approach that has been followed to utilize each data-set systematically, in order to re-vitalize a field even after 84% depletion. The paper also describes the evaluation process for all the optimization opportunities and their impact on the NPVs, to reap the maximum reward from such an old field.
Lessons Learnt from the Completion Design for a HPHT Sour Gas Field Development in Offshore Sarawak
Authors: Grant CW Graham , Bandyopadhyay Parthasarathi , Wejwittayaklung Kittipat , Mansion James Hunter , Ong Swee Hong Gary , Konganuntragul Pornchuda , Toempromraj Wararit , Jantasuwanna Prapaporn , Lee Choon How , Chia Boon Shin , Lewis David
Published: February 2023

This paper deals with the lessons learned during the completion design for a HPHT gas field (Field-X) offshore Sarawak, Malaysia. It is a carbonate reservoir with more than 500 meters of the gas column containing between 6-10 tcf of OGIP making it one of the major discoveries in recent years in this region. However, the combination of HPHT and the presence of about 18% CO2 and 2% H2S in the gas makes it a complex development, particularly for well and completion design.

To address the challenges associated with the development of this field, a taskforce was formed with personnel from all relevant disciplines to come up with an appropriate design that can help produce from this reservoir safely. The project is now in the detailed design phase where the final aspects of the completion designs are being formulated. Considering that this will be one of the first development in this area with this combination of reservoir conditions, it is expected that the lessons learned from this project will support other future developments too.

The paper discusses lessons learned during the design process specifically related to material selection for the highly sour environment, temperature modeling, identification of annulus pressure envelopes and their management, perforation philosophy, and surveillance methods for both reservoir management and well integrity.

Another aspect which affects the overall well and completion philosophy for a complex development is the challenges associated with procurement and component qualification. At this stage, the key issues are being identified and will be briefly covered in this paper.
Microplastics Baseline Study in Gulf of Thailand: First Time in Thailand
Authors: Channarong Witthaya , Taranut Nuttapong , Thamrongnawasawat Thon
Published: February 2023

The Microplastics Baseline Study was initiated with a collaboration between PTTEP and Kasetsart University. The objective of this project is to measure microplastics level in the GoT through the use of PTTEP strength in location advantage cover PTTEP offshore facilities, Koh Losin, Koh Tao, and a coastal area in Chumphon. The baseline data was developed to support the government agencies scheme in fighting with Microplastics and identification of opportunities for further improvement.

The microplastic sampling was conducted 3 times at each location and twice between 2020 – 2021 through the use of Manta net (the global standard tool) by the well trained PTTEP operators onsite. All collected Microplastic samples were sent to analyze microplastic components through the use of the cutting-edge technology such as Fourier Transform Infrared (FTIR). The result of Microplastics Baseline Study in the GoT is used as part of the Microplastics baseline data of Thailand.

The study found that the average numbers of microplastics particles in water from our 3 offshore assets are between 0.33- 1.26 pieces of mini-microplastics/m3 of water or 82,137-314,009 pieces/km2, close to the level found in the Eastern North Pacific, compared to other studies from oversea, this is more than the study from the northwest Atlantic (12,000-20,000 particles/km2) but more akin to the study of the northeast pacific (90,000-278,000 particles/km2) and less than that of Pacific garbage patch (1,345,000 particles/km2). The study also showed that the portion of offshore microplastics from fibers usually found in fishery tools like nets and fishing lines is high when compared to nearshore microplastics. (48% Fishing Net/ Line). PTTEP aims to foster collaboration among academics and private sectors in safeguarding the oceans with the ultimate goal of achieving concrete marine resource conservations.

The study marked Thailand's first attempt in conducting a baseline study of microplastics in the GoT and the world's first attempt to use a petroleum platform as a station to collect microplastic data.
Towards Sustainable Excellence & Biodiversity Protection in Upstream O & G Facility
Authors: Alsinan Ali , Rehman Khalilur , Bakodah Ahmad
Published: February 2023

Objective

The objective is to showcase the Abu Ali facility's commitment to protecting and preserving the Abu Ali biodiversity ecosystem. The project demonstrates a modern sustainable, circular, innovative and systemic approach to target the biodiversity threats in multi-dimensional aspects and transforms these threats into opportunities to improve the island's ecosystem. The island is important to Aramco's upstream operations because it houses an oil and gas production facility. The organization has determined its environmental goals from the corporate policies and vision to be as follows.

Contribute to reaching the company's and the kingdom's vision for being a net zero-carbon operating facility by 2050 and 2060, respectively, by reducing and offsetting greenhouse gases’ impact on climate. Support the Saudi Green Initiative by planting mangroves and trees in the Abu Ali Island and seeking for sourcing out the mangrove seeds to other entities. Align and adapt with carbon circular economy (CCE) approaches in reusing/repairing/recycling wasted materials and resources turning them into valuable products. Protect, preserve and enhance the Abu Ali biodiversity area to create an integrated ecosystem for wildlife, marine life, and birds. Be recognized at the corporate, nationally, and internationally as a role model in environmental protection stewardship.
Secondary Versus Tertiary Polymer Flooding: A Laboratory Evaluation in Low Permeability HT/HS Carbonate Reservoir Conditions
Authors: Ould Metidji Mahmoud , Juarez Morejon Jose Luis , Garcia Mayoral Maria Flor , Rodriguez Pardo Maria Rosario , Montes Ruiz Jesus , Lereau Damien , Monzon Vazquez Jorge , Dupuis Guillaume
Published: February 2023

Polymer flooding is a well-established EOR technique widely implemented in sandstone reservoirs. Sulfonated acrylamide-based copolymers recently proved their potential in harsh HT/HS carbonate reservoirs with pilot tests upcoming in the Middle East. While polymer flooding is often classified as a tertiary recovery method, the present study aims to evaluate EOR efficiencies in secondary and tertiary recovery scenarios. The polymer selection process and characterization in porous media are described in detail.

The study was conducted on a lab-scale at a temperature of 120°C. The salinity of seawater used for injection was 42 g/L TDS. The polymer selection was based on a thorough rheology and filterability study. The coreflooding tests were performed on limestone outcrops with permeability in the range of 40 mD. Single-phase experiments were performed to evaluate the impact of a pre-shearing step and study the in-situ rheology. Secondary and tertiary oil recovery experiments were conducted using reservoir dead oil. In all experiments, the tracer method was used to determine dynamic adsorption.

The rheology and filterability study identified the best candidate (SAV 10) among three different molecular weight polymers containing the same high-sulfonation level. The target viscosity for the desired mobility ratio was 3 cP at 120°C, achieved with a polymer concentration of 3500 ppm. The single-phase experiments suggested that pre-shearing the polymer reduced the apparent shear thickening at high velocities due to a reduction in viscoelastic properties. The best oil recovery performances were obtained in the secondary mode (polymer flood applied at Swi) with a 15% higher recovery when compared to the tertiary mode (after reaching Sorw). The results correlate with a later breakthrough for the earlier polymer flood case. In both cases the mobility ratio was comparable (0.18-0.20) and much lower than waterflooding (1.5). The polymer dynamic adsorption estimated with the tracer method was about 140 μg/g rock in brine saturated cores, decreasing to ∼100 μg/g rock in the presence of residual oil saturation. The in-situ rheology evaluation after stable recovery was reached following polymer flooding (Sorp), evidenced less apparent shear thickening, which could be related to a change in the conformation of the pores in the presence of oil.

Most studies reported on secondary and tertiary polymer flooding focused on the case of heavy-oil sandstone reservoirs. The present work introduces new insights on early implementation of polymer flooding to optimize oil production by maximizing the performance of the method in HT/HS carbonate reservoirs. Furthermore, our study provides new insights about sulfonated acrylamide-base copolymer rheology in porous media for low permeability carbonate cores.
Completion Integrity Evaluation by Distributed Acoustic and Temperature Sensing Data Acquisition Through Coiled Tubing Real-Time Telemetry System
Authors: Malik Ataur R , Espinosa Galvis Mauricio A. , Ghamdi Abdullah A. , Ahmed Danish
Published: February 2023

An intensive well integrity (WI) examination was carried out utilizing distributed acoustic sensing (DAS) and distributed temperature sensing (DTS) tools through coiled tubing (CT) with real-time telemetry system in a horizontal gas well completed with open hole (OH) multi-stage fracturing (MSF) completion. During well completion, an unexpected leak in the lower completion led the OH packers not to effectively set. The WI examination was needed to locate the leak and effectively salvage the well.

With DAS and DTS systems connected to the optical-fiber cable through the CT pressure bulk head at surface, CT conveying a bottom hole assembly consisting of conventional noise logging tool, temperature and pressure sensors, gamma ray and casing collar locator was run in the wellbore to the toe depth. The DAS and DTS data were recorded under shut-in, flowing and injection conditions keeping the CT stationed near to the toe depth. After recording DAS and DTS data in each shut-in, flowing and injection modes, noise logging was also performed by moving the CT across the entire horizontal section.

The DAS optical interrogator unit connected, at surface, to optical-fiber cable deployed in the well successfully measured the Rayleigh backscattered light to provide a local measurement of the dynamic strain, which was converted into seismic wave fronts. The purpose of running noise logging tool was to validate acoustic wave fronts and interpretation obtained from the DAS and DTS. This comprehensive investigation involving DAS and DTS allowed to detect acoustic events simultaneously at multiple points along the entire wellbore through its capacity of providing the fluid movement visualization and detection: into or out of reservoir and evaluation of flow behind pipe and OH packers. DAS and DTS have also proved to be quick and operationally efficient techniques that can be done with minimum number of trips to surface and without complex bottom hole assembly.

DAS system provided an opportunity for seismic data acquisition, where it significantly improved the efficiency of wellbore integrity diagnostic operations. A full well profile was recorded for each scenario in only minutes, rather than hours for a conventional tool survey. This paper elaborates facts on DAS data acquisition and how first time DAS data acquisition led to create a difference as comparison to the use of conventional CT.
Dual-String Barrier Evaluation Innovative Technology for Efficient P&A Operation Impacting CO2 Emissions
Authors: Zahmuwl Alhadi , Singh Kamaljeet , Wielemaker Erik , Bose Sandip , Zeroug Smaine , Assad Ali , Loov Rob , Ishberdina Gulnara , Martini Luca
Published: February 2023

Abandoning a well after it reaches the end of its life cycle requires a barrier evaluation operation across multiple strings. The traditional method for barrier evaluation requires exposing the outer casing by a cut and pull or section mill of the inner casing so that the outer casing can be logged, to verify the barrier seal. The cut and pull and subsequent inner casing/tubing recovery or section milling operations are costly and time consuming, often lasting for several days, thus increasing the overall plug and abandonment (P&A) cost and carbon emissions. This paper will describe a novel logging technology, allowing barrier evaluation of two strings simultaneously without the need to remove the inner string. The dual-string barrier evaluation technology is based on combining advanced ultrasonic multimodality physics with a multimodal deep-probing array sonic measurement providing the capability to map the axial and azimuthal material coverage in the first and second annuli simultaneously. The technology is applicable to evaluate tubing-casing dual-string or casing-casing dual-string environments.

Based on the new technology, operators are no longer required to remove the inner string to evaluate the outer string. This approach revolutionizes conventional operations by reducing P&A rig days to minimize costs and overall carbon emissions. Furthermore, when proactively performing dual-string barrier evaluation offline or rigless in a number of wells marked for P&A, operators can use the log data to optimize future rig-based operations, minimize contingencies, and possibly prioritize the rig schedule for specific wells only.

This paper discusses an offshore case study where the technology was used in two wells in the southern North Sea during the P&A phase. The measurements and observations with dual-string logging technology will be presented in addition to a validation exercise after pulling the inner string. These dual-string log measurements were subsequently used to streamline the abandonment program in realtime resulting in minimized rig time and scope, subsequently reducing overall carbon emissions.

Even though the case study covers wells from a P&A operation, the dual-string technology is equally useful in other well scenarios such as sidetracks or even monitoring barrier integrity in production wells in long-term time-lapse well integrity monitoring.

The technology can evaluate different types of barrier material such as cement or formation (shale/salt) squeeze or barite sag in both the first and second strings. Formation squeeze from specific North Sea shale (Williams et al. 2009) or salt members has been tested to act as a competent barrier.
Kasawari Carbon Capture and Storage (CCS): Unfolding the Largest Offshore CCS Project Realization
Authors: Mohamed Najib Mohamed Aiman , Zainalabidin Muhammad Aizuddin , A Rahman Aina Suharny , Nor Azlan Ahmad Zikri , Mustafa M Azlan , Veroba Grant , Nordin Norsham
Published: February 2023

Kasawari Carbon Capture and Storage (CCS) project is positioned as the world largest offshore CCS upon its commencement by 2025. It is developed as the first CCS project by PETRONAS. It targets to inject up to 3.7Mt CO2e per annum (MTPA), store approximately 80MT of CO2e over 25 years of operation. The scale is significant as it represents 9% of global CCS operation (2021) and anchors PETRONAS’ pathway for Net Zero Carbon Emission (NZCE) by 2050. This paper elaborates on the key challenges, major decisions, and learnings for value assurance in scope definition throughout Framing, Feasibility, and Concept Select phase as per Front End Loading (FEL) methodology. It serves as a future reference in overcoming similar CCS scale complexity and spur momentum for larger industry adoption to meet Net Zero Emissions target by 2050.