bluuebunny/crossref_metadata_2025 huggingface dataset:
Success of Directional Casing Drilling (DCD) Technology Delivering East Asia's Deepest and Longest High Inclination Angle 13-3/8in Casing Section, Alongside Four Other Wells Batch Drilled in Field BC
Authors: Baharudin Alif Shamir , Soong Alfred , Najmi Nik Fahusnaza Nik Mohd , Ravendrnathan Khabilashini , Chai Beng Seow
Published: February 2024

Due to persistent clay swelling issues leading to borehole breakouts in Field BC, the operator opted to seek alternative solutions to mitigate risks of wellbore stability (WBS) issues. Conventional drilling with drill pipe and running casing separately exposes the open hole for a long time, in between (Bottom Hole Assembly) BHA tripping out to casing running. This in turn results in significant water absorption by shallow clay dominant formations leading to cavings and collapse. To resolve this issue, Directional Casing Drilling (DCD) technology was explored in order to drill and case the hole at the same time. DCD technology is an enabler for batch top hole section drilling optimization of Field BC in Malaysia to drill and secure every foot drilled to section target depth (TD) in a single run and through the restricted wellhead design.

With extensive studies to mitigate the risk and challenge, the DCD technology was successfully implemented in Field BC for five wells. Moreover, several others added benefit of DCD technology such as reduced personnel head count during the operation on the rig floor and improved rig safety throughout the operation by eliminating the manual pipe, minimal chemical consumption during DCD technology with seawater and hi-vis instead of Pump and Dump (PAD) mud or Synthetic Oil Based Mud (SOBM) helps reduce the impact on the sea habitat. Most importantly, with these benefits introduced by 13-3/8″ DCD technology, this drilling campaign has saved the operator 3 days with carbon emission reduction of 126 ton.
Unexpected Rapid Corrosion in Mooring Chains Explained
Authors: Bennet D. G. , Roffey P.
Published: February 2024

High rates of corrosion had led to severe material loss in a low-alloy medium carbon steel Tether Chain from an offshore mooring system after only 5 years in service. The material losses were caused by extensive corrosion pitting and wear damage from adjacent links. Substantial levels of biomass were detected in the seabed soil and seawater at depths below 20 meters. The corrosion products on the chain link surfaces also tested positive for slime forming microorganisms indicating mature biofilm formation with inclusion of microenvironments which enabled proliferation of diverse aerobic, facultative and anaerobic heterotrophic populations. Those identified by molecular microbiological methods employed included Acid-Producing, Iron-Oxidising, Sulphate-Reducing and Sulphur-Reducing populations. The findings from the analysis confirmed a mechanism of Microbiologically Induced Corrosion (MIC), with wear rates further exacerbated by the action of rubbing wear continually exposing fresh steel surfaces which corroded in the bacteria rich environment. The repetitive, cyclical nature of the combination of rubbing and corrosion resulted in unexpected, accelerated corrosion rates.
Performance-Based vs Prescriptive-Based Abandonment Approach; A Review
Authors: Darmawan G. R. , Prasetya A. E. , Susilo S. D.
Published: February 2024

70% of Indonesia's old oil and gas wells will have no economic value and have to be abandoned as ruled by the government as it comes to the end of the well life cycle. It's part of decommissioning an entire field with environmental preservation called Abandonment and Site Restoration (ASR). There are two kinds of approaches to abandonment, prescriptive-based and performance-based. Each country has its regulations but refers to one of those two approaches. Indonesia's permanent abandonment standard is prescriptive-based, this was compared and evaluated to international permanent abandonment standards for abandonment design, and the philosophy behind it.

Literature studies are performed to understand the abandonment philosophy for Performance-Based versus Prescriptive-Based to give proper suggestions or improvements. Based on the literature study, contrast gap analysis and suggestions provided to ensure a proper permanent abandonment approach to avoid any future leaks or re-abandonment operation as part of well integrity assurance after abandonment

This paper will define and evaluate the gap analysis between typical prescriptive-based abandonment standards, like Standar Nasional Indonesia 6910-2022, Section 19.2, Abandonment of Wells; ISO-16530-1, Chapter 10, Well Abandonment Phase; OGUK, 2015a, and NORSOK D-010, Rev. 4, Chapter 9 with a performance-based approach.

The gap analysis has shown significant abandonment improvement opportunities, especially in terms of materials that can be used for plugging/isolations, reservoir isolations barriers, annular barriers, also abandonment philosophy and practice.
Smart Water Flood in Carbonate Reservoirs: an Integrated Analysis Through Zeta Potentiometric and Simulation Studies
Authors: Srivastava Vivek Raj , Sarma Hemanta Kumar , Mitra Sujit , Gopal Giridhar , Gupta S. K.
Published: February 2024

Smart waterflooding (SWF) is the science of injecting water of reduced salinity or modified potential determining ions (PDI) concentration in petroleum reservoirs for a specific brine/oil/rock system to obtain higher oil recovery efficiency. The study validates the surface interactions by zeta potentiometric measurements, estimates oil recovery, and generates relative permeability by core flood simulation through laboratory inputs, using in-situ samples of oil, water, and rock samples from one of the Giant offshore fields of India.

The main emphasis of this paper is on 1) Varying the ionic composition of the injection water and reducing salinity for injection purposes; 2) Tuning the concentration of PDI (Ca+2, Mg+2 & SO4-2) ions after fixing a reduced salinity, the surface ionic chemistry between carbonates and water results in altering the rock wettability; 3) Surface charge of oil-saturated whole core samples of rock in the presence of various diluted and smart brines were estimated by zeta potential measurements;4) Smart water flood for incremental recoveries; 5) Single porosity simulation model to match oil recovery and pressure profiles obtained from smart water floods.

The main conclusions of the study are 1) Wettability alteration in the carbonate rock tested to a more water-wet state by tuning the ionic concentrations of injection brine; 2) Zeta potentiometric studies with low-salinity waterflood (LSWF) in carbonate reservoirs can achieve positive results by: Increasing the concentration of sulfate ion to increase the zeta potential of the rock surface to an optimum level above which the deposition of calcium sulfate will not become a problem;Tuning the concentration of divalent cations, preferably calcium, such that the value of zeta potential is close to zero. At this stage, a weak bond exists between the oil and the rock surface due to a weak negative charge on the oil and a weak positive charge on the rock surface;Increasing the hydrophobicity of oil by dilution of injected brine which seems to be responsible for increasing the zeta potential and detaching the oil from the rock surface. This is due to electrical double-layer expansion which is principally caused by reduced ionic strength.

3) Smart flooding experiments indicated an increase in the overall recovery factor; 4) A positive shift in the oil relative permeability curve towards the right.

The novelty of the paper is manifested by the following findings: Potential of PDI for carbonate reservoirs at a high-temperature range and an optimum concentration of PDI, at which maximum oil recovery is possible.Confirmation of Smart water flood effect in offshore carbonate reservoir through wettability alteration.A more efficient method as compared to sequential dilution.Underlying mechanisms of waterflooding involving the chemistry of injection brine in a carbonate system are investigated.
Pushing the Limits of Coiled Tubing Intervention in Mega-Reach Wells: A Success Story Offshore India
Authors: Mirani A. , Tripathi S. , Srivastav A. , Chandak R.
Published: February 2024

Coiled Tubing (CT) operating envelopes have become challenged by the increasing length of lateral sections in extended-reach wells. CT was deployed in a 3800 mMD, mega-reach, offshore well with a 2600 m lateral section and a Measured Depth (MD): Total Vertical Depth (TVD) ratio of 3.2 to perform fishing and sliding sleeve manipulation jobs. Customized CT intervention solutions designed to perform these job objectives are presented in this paper.

A tailor-made hourglass-type 1.75 in CT string was designed since the weight limitations of the rig crane prevented the possibility of lifting 2 in CT onto the platform. A customized Bottom Hole Assembly (BHA) with self-centralizing components and an Extended Reach Tool (ERT) was used to improve CT reach while maintaining the ability to pass through shouldered profiles in the completion jewelry. Laboratory tests on various lubricants yielded a suitable metal-to-metal Friction Reducer (FR) to use while running the CT to reduce drag, prevent lock-up, and further improve CT reach in the well.

The first objective of the CT intervention was to retrieve a wireline tractor stuck between two gas lift valves. The fishing BHA comprised a mechanical JDC type pulling tool and a customized bell guide to engage the top of the fish. A hydraulically activated downward impact tool with an ERT was included in the BHA to improve the achievable set-down weight at the target depth and increase the likelihood of engaging the fish. The fish was then successfully retrieved in under 24 hours. Once retrieved, sliding sleeves in the lower completion were now accessible for CT-based manipulation. The sleeve manipulation BHA comprised a mechanical BO type shifting tool with an ERT to perform selective profile manipulation. FR was pumped along the heel section of the wellbore to achieve a friction coefficient reduction of nearly 30%, which improved CT reach and maximum set-down at the BHA. The operation was complete once the sleeve manipulation was performed successfully and the well was put on production.

CT intervention in Extended-Reach (ER) wells is technically challenging and operationally complex. Furthermore, available literature and case histories on this topic are sparse. This paper presents key learnings from both the planning and execution stages that made this challenging job successful. It aims to serve as a reference for operators and service companies to plan, develop, and execute similar CT well intervention solutions.
Improvement of Flow Coefficient Estimation with Limited Well Test Data for Real-Time Condition Analytics of Choke Valve
Authors: Visawameteekul T. , Kam T. , Thamvechvitee P.
Published: February 2024

The study discusses a method for monitoring the internal condition of choke valves to predict sand erosion using flow coefficient (Cv). The method calculates the Cv of the choke valve by utilizing eight parameters and compares it to the newly manufactured value to generate warnings. However, the availability of spot-check well test data can significantly impact the model's efficiency if tests are performed infrequently. To address this issue, the Extended Cv monitoring method is proposed in this paper.

The main purpose of this study is to develop a model for estimating Cv value in the absence of well test data. This will enhance the present Cv monitoring system, which currently only monitors the valve when the well is being tested. This study aims to bridge a gap in the Cv monitoring approach by evaluating wellhead operational data and dynamic well test data instead of relying on only static well test data. The proposed supplemental data capture dynamic features and are collected continually, which allows us to analyze the internal status of choke valves in a continuous manner. Three representative wells from the Greater Bongkot South asset are chosen as showcases for the study. The study result indicates promising results for choke valve real-time condition monitoring.

The proposed method has been proven to enable online condition monitoring in the absence of well test data. By predicting valve condition, warnings can be generated to limit operation and prevent potential harm to plant integrity and personal safety. The Extended Cv monitoring method overcomes the limitation of the well test-based model, making it more efficient by utilizing continuously measured parameters data and employing machine learning techniques.

This paper provides a useful reference for future studies to forecast Remaining Useful Life (RUL) of choke valve. The method presented in this study has the potential for expansion to other wells and has the potential to be applied in other industries facing similar issues. Overall, this study provides a valuable contribution to the development of methods for monitoring and predicting the internal condition of choke valves to address the challenges of sand production in the oil and gas industry.
Performance Evaluation of Alkali Activated Kaolinite Clay as Oil and Gas Geopolymer Cement
Authors: Melia A. , Gbadamosi A. , Agi A. , Oseh J. , Junin R.
Published: February 2024

With the increasing awareness against global warming, it is imperative to substitute Portland cement that has been used in the oil and gas industry due to huge emission of carbon dioxide (CO2) associated with its production Recently, geopolymer cement has been identified as a suitable alternative because of its environmentally benign nature and can meet the specifications of oil and gas wells. The use of kaolinite clay, which comes from natural resource as the base material contributes to the environmental sustainability and makes the cementing material cost-effective. The aim of this research is to study the effect of several external exposures curing temperatures and hydration time on kaolinite clay based Geopolymer cement. Firstly, two samples were prepared under four different curing temperatures including ambient temperature (23°C), 40°C, 60°C, and 80°C. The strongest samples from four curing temperatures were taken and cured at three different hydration times of 24 h, 72 h and 120 h. To determine the acid resistance of the samples, they were soaked in acid solution for 24 h and 72 h, 3%/12% of HF/HCl. The result shows that geopolymer cement appeared to have higher compressive strength under higher temperature and acidic condition. Moreover, geopolymer cement has better mechanical properties compared to conventional cement. The outcome of this study is beneficial for ensuring environmental sustainability in oil and gas well cementing process.
Effect of Surfactants on Oil/CO2 Minimum Miscibility Pressure of Unconventional Liquid Reservoirs-Molecular Dynamics Simulation Study
Authors: Dong Zhenzhen , Hou Tong , Ma Xinle , Lin Keze , Li Weirong , Qian Shihao , Xu Haobin , Ma Xueling
Published: February 2024

CO2 flooding has been identified as an effective method for enhancing the recovery rate of unconventional oil and gas. However, in many oilfields, the miscibility pressure of CO2 with crude oil exceeds the oilfield pressure, preventing them from achieving miscibility. This impedes the desired recovery outcomes. Surfactants present a solution to this challenge, as they can reduce the miscibility pressure between CO2 and crude oil, thereby elevating the recovery rate. Yet, the microscopic dynamics of how surfactants modulate the MMP in CO2 flooding within ULRs remain under-explored.

This research aims to delve into this gap, using molecular dynamics to elucidate the underlying mechanisms and potential benefits of surfactant inclusion in CO2 flooding applications for unconventional reservoirs.

Our study, rooted in molecular dynamics, seeks to demystify these dynamics and understand surfactants’ role more profoundly. Delving into the CO2-n-decane system, we discovered that C12PO6 and SW320 significantly alter the interfacial width by forming a molecular film, which enhances CO2's solubility in crude oil. Notably, SW320 emerged as more potent than C12PO6 in this regard. Both C12PO6 and SW320 managed to reduce the MMP of the CO2-n-decane system by more than 15%. However, when it comes to cost-effectiveness, C12PO6 shows a compelling balance between performance and affordability. Further insights revealed that the structure of the C12PO6 surfactant plays a crucial role in determining its MMP reduction capacity. Intriguingly, the addition of low carbon alcohols, especially n-pentanol, enhances the C12PO6 surfactant's surface activity, underscoring its superiority over ethanol in reducing interfacial tension.

In essence, this research offers a microscopic lens to view the intricate dance of surfactants in CO2 flooding within ULRs. Our findings provide a robust framework for refining recovery strategies in unconventional reservoirs, potentially transforming the landscape of CO2 flooding methodologies to ensure more sustainable and efficient oil and gas extraction.
Adsorption Characteristics of CO2, CH4, H2S in Kaolinite Nanopores with the Implications for Carbon Sequestration
Authors: Qian Cheng , Hu Hao , Liu Chen , Liu Yueliang , Zhao Yang , Rui Zhenhua
Published: February 2024

The sequestration of carbon dioxide (CO2) in shale formation has dual benefits of reducing carbon emissions and enhanced oil recovery (EOR). CO2 purified from industrial waste gas is the main gas source for CO2 injection into oil reservoirs, but industrial waste gas may contain impurities such as hydrogen sulfide (H2S). Impurity gases may impair carbon storage and EOR via competitive adsorption. Consequently, it is worthwhile to evaluate the adsorption characteristics of CO2, CH4, and H2S within kaolinite nanopores and their implications on carbon sequestration and CH4 recovery. Drawing upon the kaolinite nanopores model, the impact of various surfaces on the adsorption characteristics of CO2, CH4, H2S, and their mixes was examined using the Grand Canonical Monte Carlo (GCMC) methods. Various factors, including temperature (293.15-383.15 K), pressure (0-20 MPa), pore width, and gas mole fraction, are investigated in the adsorption behaviors of the mixtures in the nano-confined space. The quantity of three molecules adsorbed enhances as pressure grows and falls with rising temperature. The rank of absolute adsorbed amount is H2S > CO2 >CH4. The interaction energies of kaolinite with CO2, CH4, and H2S at 20 MPa, 293.15 K are −1421.1138, −479.0825, −2528.245 kcal/mol, respectively, and Van der Waals energy is the main component of interaction energy. Compared to 1 nm hydrophobic pores, the loading of H2S, CO2, and CH4 in hydrophilic pores under 323.15 K and 20 MPa is 22.76%, 13.17%, and 11.57% greater, respectively. The adsorption of CO2 and CH4 are negatively impacted by H2S, and the adsorbed CO2 and CH4 are reduced by roughly 59.66% and 87.11%, respectively, at 25% (molar fraction) H2S. The nanoscale mechanism of gas adsorption in the clay mineral was disclosed from a molecular perspective, which theoretically supports the application of CO2 storage and EOR projects in shale reservoirs.
A Machine Learning Based Data Driven Approach to Obtain and Estimate Potential CO2 Storage Assessment Using Sub-Surface Data Through Relative Carbon Storage Index Parameter
Authors: Tan K. , Roy S. , Consoli C. , Sakimoto N.
Published: February 2024

In efforts to achieve net-zero greenhouse gas emissions (GHG) by 2050, realizing a carbon-netural and decarbonized society, the Japanese government has initiated various projects from developing geothermal energy and hydrogen fuel cells to carbon capture storage.

Domestic and overseas CO2 storage exploration projects include the search for deep saline aquifers, depleted hydrocarbon fields (through EOR or re-purposing for long-term carbon sequestration), and un-mineable coal seams. Since geological storage is the primary focus, attention will be concentrated in this first phase on basins with saline aquifers and depleted fields.

Funded through National Low Emissions Coal Initiative, the Petrel sub-basin had been found to be suitable for the geological storage of CO2. This basin had also been identified to be one of the potential basin storages through a regional site screening study to find prospective basin and potential storage resource calculation using the rapid and cost-effective screening fairway method which maximizes the use of any available data, and helps to high grade fairways for further assessment (Uren et al, 2022).
Automated Machine Learning for Lithology Prediction Derived from Seismic Data
Authors: Qaedi K. , Barker S. M. , Simanjuntak A. , Tan T. Q.
Published: February 2024

Lithology prediction is important for oil and gas exploration to understand the complex geological features. Machine learning techniques have shown great results in the quest to understand the complexities of seismic data. Developing an accurate machine learning model is a challenging task due to complex geological data that is limited and noisy data. The study presents Automated Machine Learning (AutoML) that can handle the intricacies of seismic data for lithology prediction. A dataset comprising 14 vertical well locations was utilized to extract seismic information along the wells and lithology data based on the gamma ray log. The extracted features serve as the input for AutoML, an automatic algorithm selection process that utilizes the Bayesian optimization algorithm to identify the best-performing model. The extracted features are used as inputs for AutoML, an automated algorithm selection process that employs Bayesian optimization to determine the best-performing model. The results indicate that the Ensemble model outperforms other algorithms, achieving an accuracy of 89%, specificity of 77%, precision of 82%, F1-score of 90%, and a Matthew Correlation Coefficient (MCC) of 79%. In conclusion, the application of a classification AutoML model has demonstrated a high level of efficacy in accurately predicting lithology derived from complex seismic data. This approach effectively captures the intricate relationships and patterns within the seismic data, enabling dependable lithology predictions.
Adaptive Strategy in Execution of Crown Plug Retrieval at the First Deepwater Subsea Workover Campaign
Authors: Sare Johanes , Binilang Ronald , Pande Batara , Herputra Shanni , Rossi Massimo , Rachmat Basuki , Prayogo Denny , Melly Recia Karina
Published: February 2024

A thorough planning and preparation is very critical to ensure a successful deep-water subsea workover campaign particularly the first one in the country. A reliable back-up plan played important role in this subsea operation where the hydraulic stroking tool with the support of other downhole robotic tools, that once a contingency became the main procedure due to the successful crown plug retrieval when the conventional solutions failed.

This paper will present the planning, process, execution and lesson learned during the operations.

Wireline intervention has always been prepared for various activities in recent subsea workover campaign including being the contingency of crown plug retrieval. The conventional way to retrieve crown plugs is using slick line jarring. If this method is not successful due to certain causes and equipment limitation due to water depth (ranging between 400 and 1500 meters), a hydraulic electric stroking tool will be run to pull out the crown plugs. This new advanced electric line stroking tool is a proven and reliable solution to remove the plugs that can apply axial force up to 100,000 klbs using bi-directional hydraulic ram. In addition to the stroking tool, a detail procedure was developed involving cleaning the landing string prior RIH and deploy suction tool on the top of crown plugs to make sure that GS pulling tool run with stroker able to latch on to the crown plug.

In this campaign, at the first well from three wells workover campaign, the slick line was deployed first. On the first and second attempt, after more than 25 times, the GS pulling tool failed to latch. It was believed the crown plug fish neck was full of debris. The suction tool was run to clean out the debris subsequently after confirming the crown plug was clean, the stroking tool was run and pulled out the upper crown plug in one stroke. The lower crown plug was also successfully retrieved with the same method. From being the contingency, now deploying the electric line stroking tool continued to the second and third wells as main activity with improved operational procedure by capturing the lessons learned from each well. The operator would have added more rig days for rigging up and down the coil tubing unit to retrieve the crown plugs. This emphasizing how significant to have a very well-planned contingency solutions and being agile to overcome the challenges in the deep-water.
CFD Simulation of Factors Affecting Gas Hydrate Particle Deposition in Gas Wells
Authors: Chen Shun , Dong Pingchuan , Zhang Youheng , Cheng Peizhai , Yang Bingtao
Published: February 2024

Hydrate deposition has significantly reduced production and generated associated financial losses. Gas hydrate wellbore deposition research mostly considers the cohesiveness of hydrate particles and their adhesion to pipe walls, but the virtual mass force, pressure gradient force, and other forces between particles are not taken into account.

This study improves the hydrate particle deposition model by taking into consideration the uneven distribution of hydrate particles in the wellbore caused by gravity. The momentum equation of the hydrate aggregate incorporates the pressure gradient force and virtual mass force. To predict the amount of hydrate deposition on the production tubing, the natural gas-water flow is simulated using an Eulerian-Lagrangian framework and the shear stress turbulence model. Lastly, a sensitivity analysis is executed to scrutinize the impact of a multitude of factors on the deposition quantity of hydrate aggregates on the production tubing. These factors encompass the Saffman lift force, virtual mass force, pressure gradient force, random collision, aggregation, fragmentation, and wall roughness.

The simulation results emphasize the significant role of the Saffman lift force in the deposition of hydrate particles. Neglecting this force leads to a substantial deviation from the actual results. As the particle flow rate and wall roughness increase, there is a marked increase in the amount of hydrate particle deposition. Conversely, an increase in particle density results in a decrease in the amount of particle deposition. Specifically, when the particle flow rate escalates from 2m/s to 4m/s, the average deposition amount surges by 81.9%. An increase in wall roughness from 0.1mm to 0.5mm results in a 15.8% increase in the average deposition amount. When the particle injection amount rises from 5e-7kg/s to 5e-5kg/s, the average deposition volume amplifies by a factor of 98. However, when the particle density increases from 900kg/m3 to 2000kg/m3, the average deposition volume diminishes by nearly 32%. These findings provide valuable insights into the dynamics of hydrate deposition. The results of this study will improve current understanding of the regulations governing hydrate deposition in gas wells and contribute to the safety of wellbore flow. They also have significant implications for the prevention and management of gas hydrate wellbore.
A Novel Hydraulic Fracturing Method to Enhance Stimulation Effect for Continental Shale Oil Reservoir
Authors: Zhang Lufeng , Guo Xusheng , Wang Xinliang
Published: February 2024

Horizontal well fracturing is a fundamental means of shale oil development. Due to the tight reservoir and difficulty in replenishing energy, horizontal well fracturing generally results in low production capacity, rapid decline, and low recovery rates. To accelerate shale oil development, it is necessary to develop fracturing technologies that increase production and recovery rates. The integration of terrestrial shale oil sources and reservoirs or the specific components in crude oil makes the reservoir more prone to oil wetting or complex wetting, which is not conducive to the extraction of crude oil. The extraction of movable crude oil can lead to rapid energy attenuation. The development direction of fracturing is to use tens of thousands of cubic meters of fracturing fluid to achieve deep matrix modification and energy replacement. In light of this, this paper proposed a new nano-emulsion fracturing fluid to enhance the stimulation effect. Based on the laboratory experiments, the interfacial activity, adsorption performance, wetting inversion, and spontaneous ambition of nano-emulsion were systematically evaluated.
The Study of High Energy Materials Used as in-Situ Heat Generation for Offshore Heavy Oil Thermal Recovery
Authors: Lin Tao , Li Tianliang , Song Hongzhi , Han Rui , Gu Qilin
Published: February 2024

Thermal recovery technology is the development of the most effective way, including CSS, Flooding and SAGD, which can effectively solve the problem due to the high viscosity of heavy oil and poor mobility. However, it is difficult to recover heavy oil commercially and efficiently using conventional thermal recovery technology for offshore oilfields. That is because the limited platform area and sea water, which is commercial and easy for onshore fields. Downhole chemical thermal technology is widely used in heavy oil thermal recovery home and abroad. However, it is more used in plug removal, well bore hot washing and so on, because of its limited heat release. Due to its own advantages, high-energy material is suitable for application in heavy oil thermal recovery. Combined with the requirements of offshore oil field, high-energy material A is selected. Moreover, the heat released by the mixed reaction of agent A and agent B is used to heat the formation heavy oil, by the way of laboratory experiment and reservoir engineering calculation combined. N2 and CO2 are generated during the reaction, which reduces the viscosity of crude oil and replenish formation energy. The laboratory experiment results show that the high-efficiency chemical thermal reaction exotherm exceeds 1500 kJ/mol, which is three times that of the conventional chemical thermal reaction (300-400 kJ/mol), and no catalyst is needed. The method for controlling the rate of exothermic reaction was obtained by the research on influence factors such as salinity, solute concentration and pH. Reservoir engineering calculation results for 2 heat injection wells in a specific target block of Bohai Oilfield show that the cost can be reduced obviously. Meanwhile, agent A and agent B can be configured as an aqueous solution. The injection process is simple and the construction is convenient. This technology can be used in both huff and puff and flooding process as downhole thermal recovery. Moreover, it can be conducted in separate horizontal production wells as huff and puff, or it can be used in double horizontal well injection-production, five-spot pattern or other injection-production well pattern as WAG flooding. The injection process is simple and the construction is convenient. It is also suitable for processes such as wellbore cleaning, plug removal, thermal recovery auxiliary process and thermochemical stimulation in medium-deep heavy oil fields and offshore oil fields. It has a broad application prospect.
Impact of Impurities in CO2 Fluid to Carbon Capture, Offshore Pipeline Transportation and Sequestration Topside Facilities Design During Feasibility Study
Authors: Nazori Qurratuaini Muhamad , Hamdan M Rafiq Bin , Shaharom Murni , Yusoff Zuriyaty , Amirrudin Farahnajwa , Hashim Wan Mahsuri Wan , Anuar Astriyana , Ali Zalina
Published: February 2024

A depleted gas reservoir field located offshore Malaysia has been identified as a Carbon Dioxide (CO2) sequestration site to dispose inherent and post-combustion CO2 from domestic and foreign sources to achieve significant reduction in carbon emission for a more sustainable future. One of the key success criteria for the Carbon Capture and Storage (CCS) development is transporting and injecting CO2 fluid into the reservoir throughout field injection life. Pipelines were identified as the primary means of transporting CO2 from the capture source to the sequestration site. Transporting CO2 fluid in a 200km pipeline can be incredibly challenging due to varied CO2 fluid composition and the uncertainties in predicting CO2 fluid thermodynamic behavior. Type of impurities and Equation of States (EoS) selection will impact the thermo-physical properties of CO2 and must be considered in the design and operation of topsides facilities and pipeline. Due to uncertainties and limited data available during feasibility study, some assumptions were adopted to perform pipeline flow assurance study. This is necessary to determine the design requirement for an onshore CO2 gathering hub, compression system, pipeline and injection facilities which will be used to establish feasible operating envelope.

This study adopted a comprehensive workflow to perform CO2 pipeline flow assurance study during feasibility study to ensure any uncertainties and optimization strategies were considered at the early stage of CCS development. CO2 fluid modelling was performed considering the impact of impurities to CO2 fluid phase behavior and its thermophysical properties. Thermodynamic predictions from several EoS were evaluated prior to EoS selection. The selection of a suitable EoS is necessary to ensure robustness of the proposed design and operating strategy.

During feasibility study, several key data is undefined or uncertain. Hence a range of data and sensitivity evaluations were adopted in performing the thermohydraulic analysis. Engineering margins were proposed to provide conservatism to ensure robustness of the design envelope to meet project deliverables. As the project progresses and more reliable data is made available, the overall design can be refined and further optimized.

This paper will focus on comprehensive workflow for purpose of developing the design operating envelope and defining the recommended methodologies and EoS to be used to perform CCS topsides and pipeline design during feasibility stage to ensure any uncertainties and optimization strategies were considered at the early stage of CCS development.
Knowledge-Guided Machine Learning Method for Downhole Gauge Record Prediction in Deep Water Gas Field
Authors: Zheng Haiyan , Lin Botao , Jiang Jie , Jin Yan , Peng Long
Published: February 2024

A 1500-meter deepwater gas field in the South China Sea consisting of several wells has been installed with permanent downhole gauges (PDGs) to monitor downhole pressure. However, the high-temperature and high-pressure conditions pose a significant risk of PDG failures during the first few years of operation, which are prohibitively expensive to repair or replace. Therefore, it is essential to develop efficient models that can provide accurate estimations of the bottomhole pressure.

In this paper, we proposed a method for predicting downhole pressure by integrating physics-based models with machine learning models. First, with the historical temperature and pressure data collected from the wellheads and the PDGs, a physics-based model was built on the basis of the wellbore multi-phase flow theory to depict the gas-liquid pipe flow behavior. Afterward, machine learning methods, XGBoost and Feedforward neural network were utilized to build data-driven model for predict bottomhole pressure. Finally, based on these two models, a knowledge-guided machine learning (KGML) model that integrates the physical knowledge and the data-driven model was established to predict the bottomhole pressure. The domain knowledge from the physics-based models was incorporated into the loss function as an adaptive weight such that the physical constraints were enforced during training.

Based on the real-world data collected from two wells of the deepwater gas field in the South China Sea, a set of experiments were carried out to evaluate the proposed method for downhole pressure prediction. Compared to the pure data-driven model, the KGML model significantly reduces the distribution shift bias in pressure, improving the Mean Absolute Percentage Error (MAPE) of the pressure prediction by approximately 50%. Therefore, the KGML model can quantitatively describe the complex relationship between the wellhead temperature or pressure data and their downhole counterparts. Moreover, KGML exhibits robust performance across different well pads in the gas field, implying its extensibility to address the PDG failure challenge in a variety of deepwater gas wells. Consequently, the model can provide an efficient and economical approach for downhole measurements in deepwater regions.
CO2 Solubility in Brine Aquifers – Volumetric Considerations
Authors: Pedersen K. S. , Christensen P. L.
Published: February 2024

A thermodynamic model concept and model parameters are presented for predicting the solubility of CO2 in pure water and in water with one or more of the salts, NaCl, KCl, CaCl2 or MgCl2. A cubic equation of state with a non-classical mixing rule is used to describe the mutual solubility of CO2 and H2O. Classical mixing rules with a temperature-dependent binary interaction parameter are used to describe the interactions between H2O and salt ions and between CO2 and salt ions. A good agreement is seen with the experimental data for the CO2 solubility in brine. The solubility of CO2 in brine is important when assessing the possibilities for storing CO2 in saline aquifers. The presence of salt in an aqueous solution reduces the solubility of CO2 by 2.5-3% for each weight% of salt added. Very large amounts of water are required, if a considerable part of the CO2 produced by combustion of oil and gas is to be stored and dissolved in saline aquifers. For example, it takes approximately 50 m3 of water to dissolve the CO2 produced by burning 1 reservoir m3 of oil.
Fracture Parameter Inversion in Geothermal Reservoir Using Deep Learning
Authors: Sun Shibo , Wang Wendong , Su Yuliang , Deng Yuxuan , Li Haoyu
Published: February 2024

Proper characterization of fractures is critical for evaluating the effectiveness of fracturing jobs and optimizing well performance in geothermal energy production, unconventional reservoirs, and other areas. However, accurately determining the size, shape, and orientation of these fractures solely from microseismic events is challenging due to weak signals and noise. To address this challenge, this study proposes a novel workflow that directly builds accurate fracture models from microseismic events using the DBSCAN clustering algorithm and BiLSTM-ESMDA. The first step is to filter the noise in microseismic events using the DBSCAN clustering algorithm. Next, a 3D planar equation is employed to construct the fracture plane in each perforation segment. Based on the results of this step, reservoir simulations are performed iteratively using PEBI grids and a BiLSTM surrogate model. Multiple representation models are obtained to capture calibration uncertainty and enable subsequent studies of long-term well performance, such as history matching for production. Finally, the ES-MDA history auto-fitting algorithm is utilized to find the most appropriate fracture model for matching production data through iterative processes. The developed inversion method was implemented on a representative geothermal model with a complex fracture network. The results demonstrate that the DBSCAN clustering algorithm effectively reduces noise in microseismic activity and ensures the accuracy of fracture geometry. A large number of different fracture models can be quickly generated by the surrogate model to capture calibration uncertainty. ES-MDA is utilized to optimize the fracture model and identify the optimal solution. The fracture models constructed using this method exhibit fracture half-lengths that are 20%-30% smaller than those estimated by microseismic monitoring. Furthermore, the high level of historical fit for this horizontal well indicates that the complex fracture model is realistic for the mine site. This study introduces a new approach to building a complex fracture network. By using microseismic data and BiLSTM-ESMDA, this method provides a practical solution. The proposed workflow significantly improves the accuracy of fracture network prediction and computational efficiency compared to traditional fracture inversion methods, which are often plagued by high multi-solution, high computational cost, and difficulties with convergence.
CCS Vs Hydrocarbon - Similarities and Differences, A Geological Perspective
Authors: Lee Charlie , Tucker Owain , Seevam Patricia
Published: February 2024

Carbon capture and storage (CCS), a safe and proven technology, is a key part of a portfolio of solutions for CO2 emission reduction, estimated to account for 6-20% of CO2 reduction needed by 2050 (IEA, 2014; IPCC, 2018). The geoscience community in the Petroleum Industry plays an important role in the evaluation, exploration and appraisal of geological CO2 storage sites, especially given similarity in the key subsurface elements required in both CCS and Hydrocarbon.
CO2 System Water Solubility and Water Condensation Rate Modelling for Pipeline Integrity Management
Authors: Chen D. , Lim L. T. , Pottayil A. , Sørensen H.
Published: February 2024

In carbon capture and storage (CCS) projects, the fluid streams typically contain various impurities such as H2, N2, CO, Ar, O2, H2S, CH4 and also water. When it comes to transporting CO2 through pipelines, it is crucial to investigate the potential risks associated with hydrate formation and corrosion. These investigations often rely on the use of software modeling tools, and ensuring the accuracy of the model's parameters is of utmost importance. Key model parameters in relation to hydrate and corrosion risk include water solubility and hydrate dissociation temperatures. The accuracy of the modelling results would ultimately depend on the selection of the appropriate Equation of State (EOS) and polar model combination. This study shows how the optimal EoS model can be selected by comparing CO2 saturation pressure and solubility calculations, as well as hydrate formation temperatures, with various experimental data. This could lead to the selection of the most suitable EoS models and allow engineers to quantify the safety margin in a more effective manner. In addition, simulations were conducted to determine water solubility limits for CO2 rich fluids with various levels of impurities, providing insights into the distinct impact of each impurity has on water solubility. The impact of impurities and various design and operating factors on free water drop out along pipeline were demonstrated via a CO2 pipeline transportation case study. A separate depressurization study using a transient simulation was carried out to better understand the hydrate formation potential in such undersaturated CCS systems. In particular, the selection of most suitable EoS for CCS applications was discussed. Through this analysis it was possible to highlight the strength and limitation of various models which offers a new dimension in selecting the appropriate model.
Applicability Analysis and Mechanical Characteristics of Deep Water Suction Pile
Authors: Xu Dongsheng , Fan Jianchun , Yang Jin , Zhang Tianwei , Zhu Chunlin , Sun Ting , Zhou Yingfang , Liu Xun , Zhao Yuhang , Zhu Hong
Published: February 2024

Abstracts

The seabed soil in the deepwater surface has the characteristics of soft soil and low bearing capacity, the suction pile has the characteristics of high bearing capacity, it has broad application prospects in deep-water oil and gas drilling and production. Through the test experiments of lateral bearing capacity of suction pile after installation in place and numerical simulation of maximum stress and maximum displacement of suction pile wellhead, it is found that the bending moment load will cause the suction pile to be offset, and with the increase of the bending moment load, the wellhead offset increases, and the gasketed end shifts downward; with the increase of the tilting angle of the suction pile, the maximum transverse displacement and the maximum stress of suction pile increase, and the suction pile can protect the conductor from deformation effectively. Deformation. This study can be an important reference for the construction of wells with suction piles in deep-sea soft ground.
Multiphase Virtual Flow Metering: A Step Change in Production Management
Authors: Mishra Shaksham , Karanjkar Parag , Rawat Devina
Published: February 2024

A multiphase flowmeter capable of adapting to varying well conditions and providing reservoir transient data is an essential tool for reliable production planning and optimization. This is the main driver for the development of a multiphase virtual flow metering (VFM) module, which is intended to be an add-on to the traditional production management system, (PMS), and as a value addition for the operator.

Current physical flow metering systems have certain limitations such as a need for extensive calibration, and high capital and maintenance costs. Also, simultaneous monitoring of every producing well can be cost-prohibitive; thus, making it difficult to determine the field production efficiently and accurately. Having limited real-time field data adds a high degree of unreliability to any simulator predictions. The PMS integrated multiphase VFM described in this paper has been designed to specifically address some of these concerns in a cost-effective manner. This VFM system operates on simulated data sets as well as live field data, which are obtained at a much higher frequency to capture even short-duration transients in the field. An additional advantage of this system is that it can be deployed individually for each well, which facilitates single-well production metering.

The VFM module, based on the dynamic multiphase flow simulator, has been developed by one of the industry leaders in simulating transient behavior of flow from a reservoir through the pipeline system. Virtual results such as pressures, temperatures, and multiphase flow rates from a digital-twin of the field are used as base results to predict the field flow rates. These predicted flow rates are compared with real-time data from instruments along the well tubing at the bottom-hole and wellhead. The VFM module processes deviations between predicted and real-time data, adjusts for factors such as instrument sensitivities and field data quality, and corrects the virtual flow rates even further towards more accurate predictions. To validate and confirm this, the model also outputs the confidence rating associated with the improved predictions.

These predicted results and associated confidence levels are the final outputs from the VFM system. When integrated with the PMS, this VFM module can also configure alerts to the user in the case of any sudden risks or unwanted transients arising from the reservoir such as water breakthrough in a gas well. Upgrading the PMS with the new VFM module will empower the operator with reliable and accurate flow predictions and help overcome the production flow rate uncertainty In addition to removing dependency on field instrumentation, this VFM module will facilitate improved field production forecasting, and can help lead to timely intervention in potential production-loss scenarios caused by unexpected transients.