bluuebunny/crossref_metadata_2025_split huggingface dataset:
Revisiting GBS CO2 Removal Optimization – First Step to NET ZERO
Authors: Limpanachaipornkul P. , Wassanadilok A. , Sirijitt P. , Charoenrat D. , Borisut V. , Bunrengjit N. , Kanjana P. , Leelaratsameephanit A. 
Published: February 2024

Abstract
Great Bongkot South (GBS) GHG emission is mainly contributed by permeate flare gas from CO2 removal membrane unit. Although GBS CO2 removal operation has been continuously optimized, the focus has never come with such high intensity the world demands today for GHG reduction. Higher CO2 in raw feed gas driven by economic values makes it even more challenging for GHG reduction. This is why GBS revisits our CO2 removal operation to contribute to PTTEP's Net Zero Goal. GBS CO2 removal optimization test designed for 3 phases. First, feed gas CO2 was varied between 34% to 39% to assess magnitude of higher hydrocarbon loss and permeate flow. Second, reduced permeate backpressure to minimum to get lowest possible CO2 content in raffinate product and utilize membrane unit bypass line to match sales specification, expecting less permeate flare through less membrane flow. GBS also explores bypassing whole CO2 removal pre-treatment and membrane units in order to extend service life of pre-treatment facilities. Lastly, membrane feed temperature is minimized beyond the original limit without adverse effects from liquid condensation. From optimization tests, it was found that 1% higher of CO2 in feed gas would increase hydrocarbon loss around 2 MMscfd. Although feed-to-sales gas ratio increases with higher feed CO2, the increasing rate becomes less sensitive when increasing feed CO2 beyond 37%. This means that permeate flare flow, which corresponds directly to GHG emission, increases but at a lower ratio when operating with higher feed CO2. Reducing permeate backpressure to minimum did not straightforwardly result in significant reduction of hydrocarbon loss and permeate flare flow. However, it allowed more operational flexibility to reduce membrane feed temperature which is the key to hydrocarbon loss optimization and GHG reduction. Membrane feed temperature reduction of 1°C can lower heating value of permeate flare around 5 BTU/scf. Since then GBS has reduced membrane feed temperature from 43 DegC to 40 DegC, lowering hydrocarbon loss by 2.5% and GHG emission by 3-4%. As GHG emission reduction becomes extremely important according to global trend, high CO2 gas fields are urged to revisit CO2 removal optimization scheme. The incremental GHG reduction from optimization always presents a quick-win benefits without the need of investment. This approach can be applied for any assets in PTTEP and subsidiaries including other oil and gas producers.
A New Method to Restore Paleogeomorphology of Deeply Buried Hill: A Case from BZ Condensate Field in Bozhong Sag, Bohai Bay Basin
Authors: Liu Zongbin , Li Junfei , Ge Lizhen , Wang Pengfei , Liu Chao , Li Junming 
Published: February 2024

Abstract
The BZ Archaean hill is deeply buried and has experienced the influence of multi-stage tectonic movement. The fracture development law is complex, and the reservoir heterogeneity is strong. However, due to the low seismic resolution, it is difficult to predict the dominant reservoir. It is well known that paleogeomorphology has an obvious controlling effect on the distribution of fractured reservoirs, but conventional palaeogeomorphic restoration methods cannot restore the uplift and denudation amount in each deformation stage of BZ buried hill. Therefore, it is urgent to find a new palaeogeomorphic restoration method to provide technical support for the prediction of superior reservoirs in deeply buried hill. Firstly, the denudation amount of the denudation interface at different tectonic periods of key wells in the buried hill is obtained based on the low temperature thermochronology technique. Then, based on the mechanical parameters of the rock, the numerical simulation of the tectonic stress field is carried out according to the results of the tectonic evolution profile and the amount of denudation on the wells. The uplift and subsidence of the whole working area in different tectonic periods are obtained. Finally, under the constraint of structural simulation, the paleogeomorphology of the buried hill in different tectonic periods is restored.The result shows that the uplift rate around Bozhong sag ranges from 7.7 to 19.1m/Ma, and the amount of denudation ranges from 1000 to 2500m according to the multi-low temperature thermochronology data. The denudation rate of BZ buried hill is 8.8m/Ma, and it is estimated that the denudation amount of BZ buried hill in Indosinian and Yanshannian is 1800±300 m. Based on the results of the tectonic evolution profile and the amount of denudation on the wells, the quantitative results of the multi-stage tectonic uplift and subsidence of the typical profile is obtained through repeated forward iteration, and then the quantitative results of three-dimensional paleogeomorphology are obtained. Lastly, the favorable block of the development zone is predicted based on the results of seismic facies, stress field and paleogeomorphology. It can provide the basis for the implementation of oilfield development.Paleogeomorphology of deeply buried hill is restored by using low temperature thermochronology and numerical simulation forward iteration based on the evolution process analysis of the buried hill. By estimating the amount of denudation in different tectonic periods of the working area, the paleogeomorphology in different tectonic periods of the buried hill is finally obtained, which is the first attempt to solve the difficult problem of paleogeomorphology restoration of deep buried hill affected by multi-stage tectonic movements. This method will be used to guide the research of more similar oilfields in Bohai Bay Basin.
New Innovative Coated Crosslinked Polymer System to Minimise Unwanted Water Production at Offshore Peninsular Malaysia Wells
Authors: Aziz N. A. , Lee J. H. , Roslan A. A. , Mahbud N. , Dzulkarnain I. , Kwon S. , Nathan Y. , Ulum M. F. Saiful , Mazuni M. F. , Deraman N. A. , Tewari R. Deo , Jaafar M. Z. , Negash B. M. 
Published: February 2024

Abstract
The development of the novel crosslinked polymer system was necessary to address operational inefficiency due to excess water production for offshore Peninsular Malaysia wells. The new crosslinked polymer system is developed with scientific advancement that offers water blocking at thief zones of high permeability reservoir. The reservoir characteristics were taken into account during the polymer development to ensure compatibility and to evaluate swelling and plugging capability of the novel polymer system. The novel polymer system is aimed to increase the well production performance.The inverse emulsion polymerisation was chosen as the polymer synthesis method as it is able to create polymer in microparticle form. The novel polymer system undergoes static and dynamic performance evaluation considering the reservoir characteristics in offshore Peninsular Malaysia that are known for their high-water production. The formulation of the polymer was made through rigorous water shut-off evaluation to ensure the polymer is suitable for implementation. Several core flooding runs are conducted to evaluate the performance on deploying the new polymer system at the reservoir setting.The polymer gel restricts flow by lodging into the pore throats of the high permeability thief zones. The novel polymer system showcased high performance in plugging and high swelling capacity which is demonstrated at clastic reservoir settings of 90 °C and 2000 psi. The polymer is further coated with an innovative coating system, that enhances the polymer characteristics. The results showed different concentrations of the coating significantly increase the swelling properties to a high degree. The unique state of this novel coated polymeric microparticles, in powder form, is comprised of formulation needed for swelling and plugging without the need to inject alternate slugs of chemicals, as practised for some cases of water-shut-off treatment. This new polymer formulation with coating system is synthesised to successfully plug high permeability thief zones in offshore Peninsular Malaysia. The significant reduction of unwanted water produced is expected to minimize operational inefficiency caused by limited infrastructure at offshore production platform to accommodate excess water. In addition, the innovative polymer system assists in minimizing concerns related to corrosion and the formation of scales due to produced water.
Wellhead and Casing Hanger with Hydraulic Features to Run and Operate Downhole Casing Isolation Valve; Design and Experiences Based on Actual Installation Successes
Authors: Yeow Ming Lei , Khaidzir Khairil Azam Mohd , Abu-Jafar Feras , Ismail Hamdan , Kasim Hillmy 
Published: February 2024

Abstract
Control lines hydraulically operated downhole isolation valves were run with the production casing strings of big bore offshore gas producers to provide downhole isolation for losses and pressurised mud cap drilling (PMCD) operations. The mandrel casing hanger was re-designed and manufactured to allow hydraulic controls through the casing hanger and wellhead with a contingency technique to retrieve the control lines. Successful installation on 7 wells provided valuable lessons and confidence in applying such system.
The casing hanger and wellhead was re-designed with conduits to install control lines and provide hydraulic communication to external pumps. The wellhead has outlets to retrieve the control lines as contingency. Some design changes to provide better isolation and testing between the two hydraulic conduits were made prior to manufacturing. Workshop trials were done to prove the design. Challenges were resolved during installation with improvements in running control lines below the hanger and retrieving the control lines without nippling down the Blow Out Preventor (BOP).
Both primary and contingency techniques were applied successfully after running and landing the casing allowing the downhole casing isolation valve to be operated. Challenges during installation were damage to seals on the hanger and modifying design to retrieve the control lines without having to nipple down BOP and to pick up the casing hanger (after landing) were applied as improvements on job execution. Cementing operations with the casing hangers were successful without issues on the control lines or hydraulic conduits. Expansion of hydraulic fluids from the control lines that leak off when wells were on production at high gas rates were observed and resolved by replacing the bleed-off needle valves. The re-designed casing hanger and seals with the hydraulic outlets are working as designed with no well integrity issues even with the wells producing at high gas rates. The successful installation and production of the wells show that casing hangers with hydraulic communications to control downhole valve on casing string can be used.
Successful installation of casing hanger with hydraulic communication to operate downhole valves in casing strings provide opportunities to add devices for casing strings to have more functions e.g., hydraulically set selective seals or packers, sleeve for stage cementing. Instead of hydraulic line, electrical or conductor type lines can be run on casing string for monitoring downhole pressures, temperatures, flow or other parameters outside the casing using similar casing hangers.
Feasibility Study of Autonomous Wave-Photovoltaic (PV) Buoy to Power Subsea Equipment
Authors: Chee Sze Yan , Ng Cheng Yee , Batinathan Shankar Jonathan 
Published: February 2024

Abstract
Autonomous wave-photovoltaic (PV) buoy is a cost-effective and efficient solution for powering subsea equipment in offshore oil and gas operations. The buoy can be deployed in remote locations where fixed structures may not be feasible. This study assesses the feasibility of the buoy to electrify a subsea Christmas tree in the Johan Sverdrup field in the North Sea. A Python mathematical model is developed to evaluate the power output of the buoy. The finding shows that wave energy harnessed by using a wave energy converter (WEC) at the selected site is sufficient to electrify a subsea Christmas tree. Further investigation is required to identify the suitable subsea equipment to be electrified by the buoy.
E2E: Well Integrity Improvement Journey and WHCP Evolution
Authors: Fuan Yong Soon , Cheu Peter , Ali Mazlin 
Published: February 2024

Abstract
Wells and wellheads are essential equipment for upstream business to produce hydrocarbon product (crude oil, condensate and gas) especially wellheads where all the key isolation valves and instrumentation in place to allow the business to produce safely.
These important isolation valves consist of Surface controlled Subsurface Safety Valve (SCSSV), Surface Safety Valve (SSV) and Flowing Wing Valve (FWV) which may centrally control by Wellhead Control Hydraulic Panel (WHCP) via hydraulic systems. Routine test is conducted to ensure valves able to isolate hydrocarbon source during major accident hazards occurred as per API 14C or ISO10418 requirements.
In Upstream Malaysia, we have encountered several challenges to meet closure time on these important isolation valves and must demonstrate ALARP to allow continue production with several mitigation in place while working on solution to resolve. Issues possess a threat over a period while structured root cause analysis (RCA) conducted.
Existing aging WHCP was carried out and systematically resolved immediate issue within a year using end to end concept prescribed as Integrated Value Delivery (IVD) – a methodology cover understanding root cause of failure, improving design, organisational culture, work process and key performance indicator equipment performance monitoring for continuous improvement. In this scenario, the whole WHCP system was review from equipment ownership, related maintenance task, technical monitoring plan to prevent recurrence of major setback experience earlier. In the same time, feedback through reliability alert or lesson learnt sharing between asset and project team continues to enable a good and effective design WHCP. These improvements and lesson learnt have allowed Upstream Malaysia move from conventional WHCP that need internal combustion electric generator to a low power WHCP via renewable energy Solar or Wind.
Now with a clear structured process to manage critical equipment and right collaboration culture with end to end (E2E) in mind, WHCP was improved and able to sustain the critical function allowing Upstream Malaysia to produce the needed energy safely.
Selection of Subsea System Architectures for Offshore CCS
Authors: Olivan Ana Requejo , Ripley Andrew , Pringle Ian , Roux Arnaud , Mohd Zaid Muhammed Faiz 
Published: February 2024

Abstract
Compared to hydrocarbon production developments, subsea CO2 injection fields are characterised by a simpler subsea architecture and present lower power and low to no chemical demand. Such specification provides opportunities to reduce CAPEX by using simplified subsea injection and control systems. The extent of the subsea carbon capture and sequestration (CCS) system simplification, however, depends on the availability of technologies (including those currently under development) and the regulatory requirements that will apply to CCS developments, which may vary among regions. In this work, the elements that contribute to a technically optimised and economically efficient subsea control system for offshore CCS developments were examined.
Different subsea control system architecture scenarios that can be used to inject CO2 offshore from a carbon capture plant onshore were assessed. Each scenario represents a qualification step toward a minimalist and fit-for-purpose configuration, with the final system being a very simple and all-electric subsea architecture. We adopted a holistic approach to a hypothetical subsea CCS project, evaluating the impact of the subsea control system equipment technical readiness, CCS regulatory requirements, umbilical sizing, and installation strategy.
The CCS subsea equipment specification can simplify the profile of the subsea architecture required for carbon injection. Leaner umbilical and subsea equipment can be considered, leading to a significant saving on the project CAPEX. The subsea system CAPEX (with exclusion of the CCS pipeline) is predominantly influenced by the price and length of the umbilical and the injection tree design. The project execution profile is also positively impacted by simplifying the logistics and opening new asset opportunities (e.g., access remote reservoirs for CO2 injection).
After definition of the technical solutions and analysis of the budgetary price estimation, an all-electric scenario has been identified as the most cost-efficient architecture, with technologies that will be available and qualified for projects awarded in the near future.
Unveiling Carbon Capture and Storage (CCS) Prospects: A Basin-Scale Assessment of the Basin a, Central Thailand
Authors: Centhonglang Chayarus , Chenoll Kwanjai , Ketmalee Thanapong , Mahamat Sirichai , Thamniyom Phalaphoom , Kovitkanit Naruttee 
Published: February 2024

Abstract
This project focused on the Carbon Capture and Storage (CCS) potential of the aquifer formations in Basin A, Central Thailand, through a comprehensive basin-level assessment. The systematic evaluation process comprised four key steps: area screening, target identification, storage estimation, and suitability assessment.
Initially, a thorough review of the geological characteristics. This step identified candidate formations for detailed analysis in later stages.
Next, the geological province was divided into three geological provinces based on the similarity of structural trend and depositional environment, namely, the Northern area with a focus on F2 formation, the Western area for F3 formation storage, and the Eastern area targeting F2 formation.
After that, the project calculated the Storage Resources for specific areas, providing valuable insights into their potential storage capacity. A systematic parameter derivation method was employed during this stage to arrive at the Storage Resources.
Finally, the assessment results were used to gauge the overall suitability of Basin A for CCS purposes, considering three key criteria: reservoir efficacy, reservoir properties, and caprock efficacy. Unfortunately, the suitability assessment uncovered two significant obstacles hindering the aquifers in Basin A from being viable CO2 storage sites. Firstly, concerns were raised about their low salinity and potential conflicts with potable water usage. Secondly, the absence of a regional seal indicated that the CO2 plume might escape, rendering them less suitable for long-term storage.
Open Cell Matrix Polymer (OCMP) Filter Solution for Through Tubing Remedial Sand Control - A Case Study of Malaysian Oilfield
Authors: Mohamed F. , Rahim K. Zainul , Marimuthu R. , Johar Z. , Bakar H. 
Published: February 2024

Background
The South Furious field is located about 220 km NE of Labuan Island on the North Sabah continental shelf in water depths of between 60 and 200 ft. The field is comprised of two culminations separated by a large displacement fault. The western culmination was discovered in 1974. The eastern culmination was discovered in 1975. Reservoir type is Estuarine and Coastal/Alluvial Plain sandstones Mid Miocene Stage IVA. The field is comprised of thick successions of thin, heterogenous, interbedded sands and shales with complex faulting and uncertainties around well by well correlation. The main hydrocarbon interval depth is between 1,500 to 4,900ft-TVDSS. The field has gone through seven development stages since the first oil production in 1979. The initial understanding was that reservoir sands shallower than 3,000ft TVDSS required downhole sand control. Downhole sand control application has evolved due to lessons learned from previous stages of development. The method selected was primarily based on the formation sand properties according to criteria as per industry standard and also based on learning from historical sand control performance. Initial completion design was cased hole gravel pack (CH-GP) for shallow reservoir sands (above 3000 ft TVDSS) and cased and perforated for deeper reservoir sands (below 3000 ft TVDSS). In one of the subsequent developments, due to cost optimization, the completion design was changed to cased hole with expandable sand screens (CH-ESS) for shallow reservoir sands and cased and perforated for deeper reservoir sands. With more wells in production, it came to be understood that the entire reservoir required sand control and not just the shallow reservoir sands. Consequently, the following development changed completion design to CH-ESS for all perforation intervals. Due to hot spotting issues, most of the ESS in the shallow reservoir sands failed and caused severe sand production to surface and accumulation in the tubing and casing. Most of the shallower production zones were shut in entirely to control sand production. This is the type of completion that will be discussed further for application of OCMP filter for remedial through tubing sand control. Completion designs for more recent developments were changed to open hole with ESS (OH-ESS) and then later changed again to open hole with standalone screen (OH-SAS) for cost optimization and based on the failures observed in the CH-ESS sand control. Open hole with SAS seems the most cost-effective sand control solution for new wells for this field, however many legacy wells require remedial through tubing sand control which can be installed through well intervention to avoid costly well workovers as the field production continues to decline.
Bien Dong 20-Inch Pipeline Span Field Observation and Span Correction
Authors: Zhang Z. , Teh T. C. , Le D. D. , Nguyen T. T. , Ly D. V. , Nguyen N. T. , Le T. N. 
Published: February 2024

Abstract
The 44 km-long Bien Dong 20-inch pipeline (PL-BD2) was installed at the Hai Thach gas fields in 2013. Since the gas export pipeline started to operate, Bien Dong Petroleum Operating Company (BDPOC) has been annually conducting in-water video surveys. From the field surveys, BDPOC found significant changes in pipeline span length and location every year. Some of the free spans were observed to have exceeded the allowable span length, prompting BDPOC to perform span corrections in 2015 and 2016 by placing grout bags at over-span locations. Despite the two span correction campaigns, pipeline free spans were still observed to exceed the allowable span length at new locations in 2017. The objective of this paper is to discuss and interpret field observations of non-stationary free span based on the five in-water surveys from 2013 to 2017. Over 3000 lines of free span data have been gathered, processed or matched such that the development of over 800 free spans in five years can be traced. The free span data is then analyzed with a focus on the free span development characteristics (form/disappear, increase/reduction in length) and the effectiveness of invention work using grout bags in reducing the span length. Probability distributions of span number in one kilometer and span length are also provided. The field observations and statistical data presented in this paper may complement any future free span research on integrating the characteristics of non-stationary span, and they could be informative references for regional operators to plan their strategy for non-stationary span rectification.