bluuebunny/crossref_metadata_2025_split huggingface dataset:
Digital Transformation of Borehole Sonic Services in the Oil and Gas Industry
Authors: Donald J. Adam , Wielemaker Erik , Velez Edgar , Liang Lin , Lei Ting , Blyth Matthew , Prioul Romain 
Published: March 2021

Abstract
Sonic data are commonly acquired in exploration, appraisal, and development wells using wireline, logging-while-drilling, or through-the-bit conveyance for applications within petrophysics, geophysics, geomechanics, and geology disciplines. The measurement data require processing to obtain elastic wave slownesses (inverse of velocity) and associated attributes before the results can be used in petrotechnical workflows. The objective of the digital transformation is to streamline and automate the processing workflow to reduce user intervention and turnaround time while increasing the accuracy of results and possibly extracting more answers by fully utilizing all waveform attributes, which consequently benefits downstream applications.
There are four workflows that are the foundation of the transformation. They support the overall goals of reducing user interactions and providing robust results in a timely manner for continuous slowness logs. First, data-driven inversions done during acquisition with automatic quality control and interpretation flags immediately provide assurance about the data quality and identify formation intervals that require further evaluation. Second, automatic dipole-flexural shear extraction is done using physics-based machine learning (ML) where purely data-driven models are inadequate due to borehole or geological conditions. The physics-based ML utilizes cloud-based computing that is needed for large volume synthetic data generation and neural network training. Third, a multiresolution analysis of the monopole waves for the compressional slowness uses automatic peak detection on multiple receiver levels removing any subjective manual labeling after the semblance processing. Finally, the multimode (flexural and Stoneley) inversion determines anisotropic constants and accounts for mud-speed variations in the borehole, including detailed uncertainties.
The new methods address underlying concerns most users and waveform processing experts already observe in their sonic deliverables. Enabling wellsite algorithms to be more automatic and data driven improves the robustness of the field deliverables and provides insight into the quality of the data. For the shortcomings with regards to borehole or geological conditions such as laminations, sharp lithological transitions, or the presence of anisotropy, the physics-based ML is shown to honor the physics of the dipole flexural mode, while the multiresolution for the monopole provides physics-based reasoning for discrepancies between the geological layering and receiver aperture. By incorporating the range of results derived from the inversions with advanced interpretations such as transversely isotropic constants, these uncertainties can be further used in stochastic models in downstream workflows. All these methods are fully automated and can be done in a short timeframe to be used without doubt in operations.
Integrated Reservoir Geomechanics Approach for Reservoir Management
Authors: Hon Vai Yee , Mat Piah M Faizzudin , M Fauzi Noor 'Aliaa , Schutjens Peter , Agarwal Binayak , Harris Rob 
Published: March 2021

Abstract
An integrated 3D dynamic reservoir geomechanics model can provide a diverse 3D view of depletion-injection-induced field stress changes and the resulting deformation of both reservoir and overburden formations at various field locations. It enables the assessment of reservoir compaction, platform site subsidence, fault reactivation and caprock integrity associated with multiple production and injection reservoirs of the field. We demonstrated this integrated approach for a study field located in the South China Sea, Malaysia, which is planned for water injection for pressure support and EOR scheme thereafter. Reservoir fluid containment during water injection is an important concern because of the intensive geologic faulting and fracturing in the collapsed anticlinal structure, with some faults extending from the reservoirs to shallow depths at or close to the seafloor.
Over 30 simulations were done, and most input parameters were systematically varied to gain insight in their effect on result that was of most interest to us: The tendency of fault slip as a function of our operation-induced variations in pore pressure in the reservoir rocks bounding the fault, both during depletion and injection.
The results showed that depletion actually reduces the risk of fault slip and of the overburden, while injection-induced increase in pore fluid pressure will lead to a significant increase in the risk of fault slip. Overall, while depletion appears to stabilize the fault and injection appears to destabilize the fault, no fault slip is predicted to occur, not even after a 900psi increase in pore pressure above the pore pressure levels at maximum depletion. We present the model results to demonstrate why depletion and injection have such different effects on fault slip tendency. The interpretation of these geomechanical model results have potential applications beyond the study field, especially for fields with a similar geology and development plan. This is a novel application of 3D dynamic reservoir geomechanics model that cannot be obtained from 1D analytical models alone.
Feasibility Study of Offshore Hybrid Technology for High CO2 Gas Field Monetization
Authors: Ahmad Zuhdi M. Faizan , Rahman F. Hadana , Shahjavan Hamid , Mas’od M. Azlan , Salihuddin R. Suhaib , Zulkepli N. Ashikin , Alias Azila , Jalani M. Yazid , Yiin Tan Kin 
Published: March 2021

Abstract
The CO2 capture technology is well understood in the oil and gas industry. However, to unlock the Hydrocarbon from an ultra-high CO2 offshore field (more than 70% mol), special attention is needed to capture CO2 for a field development to be economically attractive. Therefore, the current technology inventory needs to be studied to achieve project goals and at the same time achieving Carbon Capture and Storage (CCS) requirements. A hybrid of multiple carbon capture technology will help to improve the hydrocarbon (HC) loss, reduce both operational and capital cost and minimize overall auto consumption. The hybrid of cryogenic distillation (CryoD), membrane and supersonic gas separation (SGS) was studied to explore its feasibility.
To enable ease of CO2 transport and handling, CO2 is preferred to be in liquid form. In order to achieve this, CryoD technology is the preferred solution for bulk removal. CryoD is also able to cater to the feed gas fluctuation and becomes a robust candidate for high variance feedstock. However, being dependant on sub zero working temperatures, the system will require larger equipment footprint and tonnage.
The focus of the study is to evaluate the sensitivity impact of an operating condition on the Hybrid configuration of CryoD + membrane (CM) and CryoD + SGS (CS. Areas of focus will be equipment tonnage and footprint, power consumption and eventually cost (CAPEX & OPEX).
The monetization of ultra-high CO2 gas field is then made feasible by using hybrid Acid Gas Removal Unit (AGRU) to meet sales gas specification. The CryoD + membrane technology is the preferred solution for offshore system.
Optimising Well Times Through Drilling Connection Practices
Authors: Mohd Mazlan Faisal , Ahmad Redzuan Ahmad Zhafran , Amiruddin Mohd Idzwan , Ramli Ahmad Faizal , Slagel Pete , Mondali Mondali 
Published: March 2021

Abstract
From an operator's perspective, many operational instructions are written implicitly that are not sufficiently detailed to optimize drilling efficiency. Upon a review of several partner operators’ drilling performance, it was noticed that there was a significant focus on the following aspects of technical limit drilling: ROP, tripping speeds, offline activities and connection times. One operator specifically reviewed Gulf-of-Thailand best practices and implemented them in Malaysia.
One of the significant areas of improvement includes drilling connections. In the previous version, PETRONAS Malaysia Drilling Operations follows a conservative ERD connection method requiring to ream a single/stand, take a good survey a minimum 10m off bottom prior to making a connection and applied to all wells regardless of inclination or complexity. This was in response to risk of stuck pipe incidents happening during these critical static periods.
A comparison of the connection times after their change in practice compared to PCSB practices given the same tools and well complexity indicated massive potential time savings with no additional costs. A change in the drilling connection practices could easily save almost half of this particular "flat time" with no significant risk, amounting to a possible saving of almost 26 hours in a well of around 3000m MDDF. This also led to a better understanding of the impacts of certain "rule-of-thumb" practices that needed to be questioned from time to time.
This comparison coupled with many existing literatures available allowed a data-driven approach to improving well times. Some of this information is easily glossed over considering the only time-based data most wells refer to would be the Daily Drilling Report. This paper also emphasizes the importance of data collection and usage of historical databases to search for more opportunities in terms of safety, cost and time.
Subsurface Back Allocation: Calculating Production and Injection Allocation by Layer in a Multilayered Waterflood Using a Combination of Machine Learning and Reservoir Physics
Authors: Rafiee Javad , Calad Serrano Carlos Mario , Sarma Pallav , Plotno Sebatian , Gutierrez Fernando 
Published: March 2021

Abstract
Allocation of injection and production by layer is required for several production and reservoir engineering workflows including reserves estimation, water injection conformance, identification of workover and infill drilling candidates, etc. In cases of commingled production, allocation to layers is unknown; running production logging tools is expensive and not always possible.
The current industry practice utilizes simplified approaches such as K*H based allocation which provides a static and inaccurate approximation of the allocation factors; this manual approach requires trial and error and can take several weeks in complex fields.
This paper presents a novel technique to solve this problem using a combination of reservoir physics and machine learning. The methodology is made up of four stages:
Data Entry: includes production at well level (commingled), injection at layer level and injection patterns or a connectivity map (optional) Gross Match: in order to match gross production for each well, the tool solves for time-varying layer-level injection allocation factors using a total material balance equation across all wells. Phase Match: having the allocation factors from the previous step, the tool automatically tunes various petrophysical parameters (i.e. porosity, relative permeability, etc.) in the physics model for each injector-producer pair across all the connected layers to match the oil and water production in each producer. An ensemble of several models can be run simultaneously to account for the probabilistic nature of the problem. Output: The steps 2 and 3 can be performed at pattern level for all connected patterns or for the whole field.
The application of the technology in a complex field with 80+ layers in Southern Argentina is demonstrated as a case study of the benefits of the adoption of the technology.
Prediction Of Shut-in Bottom-hole Pressure From Wellhead Pressure Considering Transient Behaviour Of Hydrostatic Pressure Loss During Shut-in
Authors: Maki Satoshi 
Published: March 2021

Abstract
Shut-in bottom-hole pressure (SIBHP) is key information to monitor reservoir depletion and thus to evaluate gas in place for a gas field. Permanent downhole gauges are widely used to continuously measure bottom-hole pressure especially for subsea wells. However, when gauges fail, a large cost of workover for gauge replacement is a major problem. In case of the gauge failure, SIBHP hence needs to be estimated from measured surface data such as wellhead pressure (WHP) and wellhead temperature (WHT). The use of WHT for subsea wells however leads to a large error of the SIBHP calculation because sea current significantly affects WHT readings during shut-in. This study aims to develop a correlation methodology to predict SIBHP from surface data without using WHT.
We have developed a linear correlation of hydrostatic pressure loss during shut-in with superposition time to predict SIBHP from WHP. Using superposition time of well production status with zero or one indicator effectively accounts for transient behaviour of hydrostatic pressure loss caused by cooling of wellbore fluid and pressure build-up. The transient behaviour differs by individual wells. Hence, the coefficients of the correlation were calibrated well by well to reproduce observed SIBHP.
The correlations were applied to the Ichthys gas-condensate field located in the Browse Basin, North West Shelf of Australia. SIBHP trends are reasonably reproduced by the correlations after calibration. A blind test was performed using additional 18 months production data to investigate the predictability of the proposed correlation. As a result, high accuracy of the prediction is confirmed with an average absolute error of approximately 0.4% for the test period. The SIBHP of wells in which downhole gauges have failed is predicted by the calibrated correlations, and the predicted SIBHP is utilised for the reservoir management of the Ichthys field.
We present the novel methodology to predict SIBHP from observed surface data without WHT for subsea gas-condensate wells considering the transient behaviour of hydrostatic pressure loss. The proposed correlation provides accurate prediction of SIBHP in case of the gauge failure.
Verification and Application of CTV Technology for Deep Sea Crude Oil Offloading in Brazil Project
Authors: Wang Zhixiang , Zeng Xianglin , Li Bo , Xiao Yue 
Published: March 2021

Abstract
In view of the problem of high risk and high cost of deep-sea crude oil export technology, this paper starts with the problem that DPST (Dynamic Positioning Shuttle Tanker) in Brazil's one deep sea project compulsorily be used in offloading operation. From coordinating and participating in the comparison and selection of offloading schemes from CNOOC and individual partners, to the raising of technical proposal CTV (Cargo Transfer Vessel) and subsequent carrying out of ship design, construction, sea trial and until actual application, this paper fully discusses and verifies CTV's correctness and adaptability. As the world's first unique technological solution for the offloading issue. its excellent security and low cost advantages will assure CTV a greater role in the field of deep sea oil offloading and other marine areas.
A Compelling Case: Time to Change Minimum Curvature Survey Method for Well Engineering Calculations
Authors: Samuel Robello 
Published: March 2021

Abstract
Several calculation methods have been proposed by the researchers in the past with varying degree of precision. These result in different wellbore position estimation. The survey calculations and positions are used in engineering calculations such as torque and drag, drill ahead prediction, displacement of the string, SAG correction etc. Since the survey calculations are the underpinning starting point for the engineering formulations, considerable errors are introduced in the engineering calculations. Most widely used method in the industry is minimum curvature which assumes a circular arc in an inclined plane and this method is better than some of the previously introduced methods like balanced tangential method, average angle method etc. It has also been seen that, the radius of curvature method is more suitable for a rotary mode of drilling, whereas the minimum curvature method aligns when slide drilling. However, using the minimum curvature method, introduces discontinuity at the survey course intervals. This type of constant curvature model due to discontinuity may result in the omission of some contact forces which will result in the under prediction of the hookload or the stresses in the drillstring components or casing or drillpipe wear calculations. This further results in the discontinuity in the engineering calculations also and will be more pronounced when the wellbore twists and turns. To alleviate this problem, wellbore smoothening is done by using advanced survey methods such as spline, natural arc method, curvature bridging etc. A reliable inclination and directional continuous surveys also enable smooth and continuous wellpath making the problem with the minimum curvature method to vanish.
This paper presents the research findings not only on the relationship between the minimum curvature method and engineering calculations but also the inherent problem in the commonly used survey calculation methods. It has been shown that both wellbore curvature as well as the borehole torsion are necessary to relate to the mechanical parameters that are used in the engineering calculations such as bending moment, side force and string position.
A New Method of Reproducing Rock Samples with Rough Surfaces for Testing Conductivity: A Case Study on Shale Propped Fractures
Authors: Chen Chi , Wang Shouxin , Lu Cong , Wang Kun , Lai Jie , Liu Yuxuan 
Published: March 2021

Abstract
Hydraulic fracturing technology provides a guarantee for effective production increase and economic exploitation of shale gas wells reservoirs. Propped fractures formed in the formation after fracturing are the key channels for shale gas production. Accurate evaluation of local propped fracture conductivity is of great significance to the effective development of shale gas. Due to the complex lithology and well-developed bedding of shale, the fracture surface morphology after fracturing is rougher than that of sandstone. This roughness will affect the placement of the proppant in the fracture and thus affect the conductivity. At present, fracture conductivity tests in laboratories are generally based on the standard/modified API/ISO method, ignoring the influence of fracture surface roughness. The inability to obtain the rock samples with the same rough morphology to carry out conductivity testing has always been a predicament in the experimental study on propped fracture conductivity. Herein, we propose a new method to reproduce the original fracture surface, and conductivity test samples with uniform surface morphology, consistent mechanical properties were produced. Then, we have carried out experimental research on shale-propped fracture conductivity. The results show that the fracture surfaces produced by the new method are basically the same as the original fracture surfaces, which fully meet the requirements of the conductivity test. The propped fracture conductivity is affected by proppant properties and fracture surface, especially at low proppant concentration. And increasing proppant concentration will help increase the predictability of conductivity. Due to the influence of the roughness of the fracture surface, there may be an optimal proppant concentration under a certain closure pressure.
Research Method of Phase Behavior in Gas-Crude System and the Application in L Block with HP/HT
Authors: Jiang Tongwen , Zhou Daiyu , Wu Yiming , Chang Lunjie , Lian Liming , Wu Zangyuan , Zhou Wei , Fan Kun , Tang Yongliang , Yu Hongwei , Bian Wanjiang , Shao Guangqiang , Fan Jiawei , Wu Lin , Huang Lan , Kuang Xiyu , Fan Jin , Li Yang 
Published: March 2021

AbstractThis paper provide improved phase behavior models, trying to mitigate the problem that phase behavior of gas-crude system is difficult to describe in L block with low permeability and high water cut in China. This situation leads to a series of problems in CO2 flooding process and lower recovery up to expectations. The models is evaluated to possess both high calculation speed and accuracy compared with existing others.Characteristics of CO2-crude systems had been considered into repulsion-attraction type EOS (equation of state) based on the analysis of repulsion parameter and attraction parameter in EOS, and the improved EOS had been applied in developing calculation method of MMP (minimum miscible pressure). No ideality of CO2-crude systems had been considered into mixing rules of CO2-crude systems based on analysis of mixing rules of repulsion-attraction type EOS. Promotion had also been put into the obtain methods of parameters in phase behavior, including density, viscosity, MMP, critical parameters of plus components etc. All these methods are applied in L Block.The phase behavior models of CO2-crudes system promoted in this paper mainly include EOS, mixing rule and viscosity model and have been applied in CO2 flooding process in T Reservoir. The relative error of density calculation is reduced from 7% ∼ 20% to less than 1%and the modified EOS is applied to predict the MMP of the CO2-crude systems from 8 different blocks in T reservoir. The modified EOS also works well for the relative error of MMP prediction is reduced from 20% ∼ 70% to less than 5%. Compared with the existing mixing rules, the modified mixing rule is with higher calculation speed and accuracy. The relative error of components mole fraction calculation is reduced from 30% ∼ 80% to less than 10%. Compared with the existing viscosity models, there are large improvements of the modified viscosity model in accuracy. The relative error of viscosity simulation is reduced from more than 50% to about 5%. According to the simulation results, C2∼C15 are the key hydrocarbons with positive effect on the miscibility of CO2-crude systems, while C16+ are the key hydrocarbons with negative effect. The recovery of the pilot has increased by 23% by these methods.The improved phase behavior models provided in this paper possess as good performance as existing models in calculation speed, and accustom a big step forward in simulation accuracy. The modified components of the models also partially complete physical meaning in describing phase behavior of CO2-crude system. All the models mentioned above are finally applied in L block with HP/HT and high water cut and obtained an increase in recovery by 19.2%.