bluuebunny/crossref_metadata_2025_split huggingface dataset:
Capillary Pressure Corrections, Quality Control and Curve Fitting Workflow
Authors: Al-Bulushi Nabil , Kraishan Ghazi , Hursan Gabor 
Published: April 2019

Abstract
Capillary pressure is a crucial step in reservoir properties definition and distribution during static and dynamic modelling. It is a key input into saturation height modelling (SHM) process, understanding the fluid distribution and into reservoir rock typing process. Capillary pressure models provide an insight into field dynamic for the identification of swept zones and provide another calibration besides the log calculated saturation. Capillary pressure curve tends to be more complex in carbonates in comparison to sandstone reservoirs because of post deposition processes that impact the rock flow properties, hence complex pore throat size distribution (uni-modal, bi-modal or tri-modal). Therefore, accurate determination of this property is the cornerstone in the reservoir characterization process.
Capillary pressure can be obtained using several experimental techniques, such as mercury injection (MICP), centrifuge (CF) and porous plate (PP). Each method has its own inherited advantages and disadvantages. The MICP method tends to be faster, cheaper and provides a full spectrum of pore throat size of a plug. Whereas, the PP method can be carried out at reservoir conditions with minimum required corrections.
In this paper, a detailed workflow for quality control capillary pressure is discussed. The workflow is sub-divided into three main parts: Instrumental and experimental level, core measurement level and logs level. Experimental level starts with proper designing the actual procedure of the capillary pressure experiment. Parameters such as pore volume, bulk volume and grain density are investigated at core measurement level. In geological-petrography montage, all petrography data; X-Ray Diffraction (XRD), Scanning Electron Microscope (SEM), thin section and computed tomography scan (CT) are used along with the capillary pressure curve for assessment. Comparing various methodologies of experimental technique carried out on twin plugs, if exist, are also investigated. The capillary pressure that passes the previous QC steps is used as input into saturation-point comparison as a logs level QC. The saturation calculated from capillary pressure is compared to log-derived water saturation eliminating any issues with porosity and permeability of the trims and provides insight to the uncertainty level in the model. As an additional step, the MICP measurements are fitted with bi-modal Gaussian basis functions with two practical benefits. First, the quality of this fitting is a useful indicator for the evaluation of pore structure complexity and the identification erroneous measurements. Second, the fitting parameters are useful inputs for geological interpretation, rock typing and SHM. This rapid and automated workflow is a useful tool for screening, processing and integration of large-scale capillary pressure data sets, a key step in integrated reservoir description, characterization and modelling.
Successful Application of Specialized High-Performance Water Based Drilling Fluid to Drill a TAR Section
Authors: Abahussain Abdullah , Pino Rafael , El-Dakroury Hesham , Addagalla Ajay 
Published: April 2019

Drilling a TAR formation has never been easy due to the sticky nature of the material. TAR sands are sandstone formations saturated with bitumen or heavy oil and are soft and poorly consolidated. The sandstone is usually water-wet in the formation with the sand grains held together mainly by the bitumen. Weathering and biological process results in loss of the lighter oil fractions, leaving behind the very viscous, solid or semi-solid heavy residues. Bitumen deposits are found in more than 70 countries globally, with large outcrops in Venezuela and Canada.Drilling TAR sections with conventional drilling fluid systems, either water-based or oil-based, has proven ineffective. Some factors that must be considered are wellbore enlargement, accretion, screen blinding, erratic torque and drag, larger cuttings and temperature conditions. TAR tends to be mostly hydrocarbon-based and it swells, softens or dissolves in oils or in synthetic base-fluids that the industry uses for oil Based Muds (OBM) or Synthetic Based Muds (SBM). Drilling with OBM or SBM tends to lower the mechanical strength of the TAR, exacerbating any tendency to mobilize into the wellbore. A conventional water-based mud with basic inhibition and minimal reduction in pore pressure transmission may not be helpful in mitigating the challenges associated with wellbore stability, accretion, torque and drag complications.A High-Performance Water Based Mud (HPWBM) was designed to drill these types of complicated intervals, nearly matching the drilling performance of oil-based mud (OBM) and delivering a gauge hole. This paper presents a successful drilling through a TAR section using a HPWBM after failures using OBM. The previous attempts were carefully studied to identify the challenges associated during drilling and considered while designing this HPWBM.The TAR interval was successfully drilled without any drilling fluid related Non-Productive Time and completion set on bottom without any problems. This approach for drilling fluid chemistry provides an environmentally sound replacement for the current drilling fluids to drill TAR sections.
Optimization of Suitable Measurement Position Through Fluid Dynamics in Early Kick Detection
Authors: Sun Hehui , Lao Liyun , Li Dengyue , Tao Qinglong , Ma Hong , Li Huaiyu , Song Changhong 
Published: April 2019

Abstract
More and more early kick/loss detection (EKLD) devices are being used in drilling operations, whether in the field of onshore or offshore drilling. In the field of deepwater and offshore drilling, high-precision electromagnetic flowmeters and Coriolis flowmeters was used to measure the inlet and outlet flow rates of drilling fluids. Good effect was achieved, but are affected by drilling fluids, space limitation of the wellsite and production costs when in the field of shore drilling, engineers usually use the paddle- flowmeter and ultrasonic liquid level meter to measure the inlet and outlet flow. It exists the problem of low measurement accuracy and prolonged warning time. In order to improve the accuracy of measurement and the accuracy of early warning, the electromagnetic flowmeter has been studied in terms of flow measurement at the outlet of on-shore drilling. The study found that the installation position of the electromagnetic flowmeter in the V-shaped test pipeline is a key factor that determines the accuracy of measurements. The influence of different fluid types on the measurement was studied by fluid dynamics. The fluid model was established using Ansys fluent software, and the boundary conditions were set in conjunction with the relevant parameters of the drilling fluid. It was found that the descending segment of the V-shaped pipeline was suitable in the state of laminar and dispersed flow. It is an appropriate mounting position for the electric flow meter; for the slug flow, the rising section is a suitable installation position. The theoretical conclusion is verified by laboratory simulation and field tests. The results of theoretical research were used to optimize the design of the test pipeline, and the problems of transient large flow passage and solid-phase debris deposition in the field were solved, and good results were achieved. An automatic grouting module was developed based on the accurate measured outlet flow data. The automatic grouting operation is very helpful for the construction process of drilling and triping, improved the safety level of well control, and laid a good foundation for the large-scale application of EKLD devices in the field of shore drilling.
Effective Fracture Thickness Estimation Using Microseismic Events Distribution
Authors: Shimoda Naoyuki , Shapiro Serge A. , Reshetnikov Anton 
Published: April 2019

AbstractHydraulic fracturing is carried out in most shale gas fields to enhance reservoir permeability. Thousands of microseismic events are observed with geophone arrays during fracking stages. Microseismic hypocenter distributions are essential information to delineate stimulated reservoir volume (SRV), and there are some useful automatic processing tools to get hypocenter locations. However, recorded seismograms contain noise and complex phases that cause ambiguity in the data processing. In addition, the velocity model selected has a great influence on the accuracy of the hypocenter information.In this research, to enhance the accuracy of microseismic event hypocenter locations, we picked P and S phases using an array seismogram volume (ASV). The ASV consists of shot gathers and receiver gathers of selected events and receivers. The events should be limited to those that have enough waveform similarity. Once we pick an onset time of a single trace in the ASV, the picked seed trace is compared with neighboring traces using cross correlation; most of the onset times in the ASV are picked automatically. Because the process requires picking of single traces, we call this procedure semi-auto picking. This semi-auto picking tool can reduce the time needed for manual picking and the process is efficient and provides high-quality results.Shale sediment are frequently characterized by anisotropic parameters. The sediments in Barnett, our study area, also show anisotropy. Therefore, an accurate velocity model is required to achieve precise microseismic event analysis. A tilted layer orthorhombic velocity model was adopted in this study. P-wave sonic and gamma ray logs were available for a reference well located close to the study area. The 3D seismic survey interpretation provided a tilted layer angle. The principal horizontal stress direction was provided by a previous study in Barnett. Using this geoscience information as constraints, a number of optimized parameters could be reduced. Seven Thomsen parameters and the Vp/Vs ratio of the defined layers were optimized using perforation shots.A grid search location approach was applied to locate 932 events during a single fracking stage. To obtain final locations, the following objective functions were combined: (1) P, Sh, and Sv travel time misfits; (2) travel time differences between receivers; (3) travel time differences between different wave phases; (4) travel time differences between microseismic events and master events (perforation shots); (5) P phase polarization; and (6) P phase polarization differences between microseismic and master events. Spatio-temporal behavior of the located event cloud was investigated using R-T plot analysis. The SRV was observed to grow with the injection volume in this stage and the effective fracture thickness was almost 10 mm after treatment.
Intelligent Under Reamer A Solution for Lean Casing Profile
Authors: Khaw Aik Loong , Nguyen Ngoc Thanh Phuong , Vu Quach Anh , Miguel Dennis 
Published: April 2019

Abstract
In Vietnam, there was a need of a lean surface casing due to restricted drift inside diameter (ID). The 2nd slot of the splitter conductor only have 13-1/2" ID max pass through. The practical option is to drill with 12-1/4" bit and open to 14-1/2" hole to set 11-3/4" casing OD. Similar reasoning for the intermediate hole that will require to under ream the hole from 10-5/8" bit to 12-1/4" hole and set 9-5/8" casing OD. Although these under reaming operations are commonly practiced, the technical limitations are still inefficient and compromising. Conventional reamers still have limited activation/deactivation cycle for operational flexibility and long rathole of the reamer to bit depth for casing shoe placement.
The long awaited technology is now available with the presence of intelligent reamers that have unlimited activation & deactivation cycles and can be placed directly above the rotary steerable system for shortest possible rathole. The setup is to combine two intelligent reamers in a single BHA. The 1st reamer placed strategically on top of the MWD & LWD tools while the 2nd reamer is directly above the rotary steerable system tool. As both reamers can be both activated and deactivated through downlinking, the reamer has to be activated simultaneously to control the risks associated with hole opening and LWD data acquisition. The 1st intelligent reamer will be activated first while drilling the section formation and the 2nd intelligent reamer will then be activated at section TD to ream and shorten the rathole. For the purpose of cleaning the hole effectively, both reamers can be deactivated to execute high flow and RPM without creating new cuttings from the reamer blades and avoid making a bigger hole at the low side.
This enabled shoe to shoe drilling while under reaming and achieving less than 10m rathole. These operational capabilities saved at least 50% of the section rig time compared to having a 2 trip system. Combination of reduced casing shoe rathole and open hole exposure mitigated the well bore instability risks and helps in managing mud weight for both hole section intervals. The unlimited activation cycle provided flexibility in operations particularly in dealing with hole cleaning and wiper trips. Plus, the intelligent reamer provides realtime reamer diameter which gives confidence on the drilled hole size for casing running preparation and decisions.
Intelligent reamers have unique tool features that differentiate from the rest of current industry technologies. This feature helps to eliminate the risk of under-reamer balling, which improve the rate of penetration. The success of the operation has spread throughout operators in Vietnam, and now the intelligent reamer is considered as a game changer application in drilling lean casing profiles.
Geomechanical Risk Evaluation for Developing Karstified Limestone Reservoir in Offshore Sarawak, Malaysia.
Authors: Mohd Ali Siti Syareena , Teng Kevin Ging Ern , A Jalil M Azran , Sedaralit M Faizal , Trianto Adi , Wan Sagar Siti Fatimah Sarah 
Published: April 2019

Abstract
The scope of the geomechanical study is to investigate the risk associated with different reservoir depletion strategies and to numerically simulate the geomechanical response of the reservoir rocks. The study focused on the large karstic distribution of the reservoir for the prediction of the best drilling direction and optimum well trajectories, and also to model the pore collapse behavior observed in the high porosity carbonate which will result in surface subsidence and impact the platform facilities placement.
A methodological risk evaluation approach based on numerical simulations with stringent experimental programme has been applied to the field study. The regional geological understanding and operational experience of the nearby fields have been considered for the study via extensive assessment of constitutive models relating to pore collapse. Advanced 4D geomechanical simulations were carried out to incorporate the seismic-based karstic models and to strengthen understanding of the pore collapse phenomena during reservoir depletion. The obtained prediction results were compared to nearby fields and subsequently use for wells, facilities planning and engineering considerations.
The results obtained in the study identified a few key outcomes which are being considered for detailed surface engineering design and well planning. The results have impacted the decision to place the location of the platform away from the center of the seabed subsidence bowl. The predicted reservoir compaction and subsidence described the rate and the magnitude of the subsidence which are use to design the height of the platform to mitigate potential damage induced by wave deck shearing. In addition, the distribution of karst has been mapped through seismic imaging and incorporated in the geomechanical modelling. The results are also used to determine the hazard of the weak zones in each formation and high stress anisotropy regions which are to be avoided for future well placement and to be used for well trajectory optimization. Key findings of the geomechanical-related risk have been identified and considered in the field development plan. Consequently, a Risk Ranking Criteria incorporating the results of advanced simulations and rock testing programme have been developed based on comprehensive weightage and the technical categories.
The paper offers a detailed insight on the geomechanical risk evaluation obtained using 4D finite element coupled reservoir geomechanical simulations. The study addressed the challenging development of a highly karstified limestone reservoir by offering valuable inputs for the well design and facility engineering through prediction of reservoir compaction and seabed subsidence, best drilling direction and optimum well trajectories. This will avoid potential geomechanical related hazards and ensure adequate operational safety levels.
Study and Field Application of New Agent for Casing Repair in High Temperature and High Salinity Reservoir
Authors: Meng Xiangjuan , Pan Zhaocai , Chen Defei , Su Zhou , Wang Peng , Liu Ju , Shen Jianxin , Cao Xianping , Bai Xiaofei 
Published: April 2019

Abstract
Casing failure probability is high in Tarim Oilfield, due to high pressure high temperature and high sality operational environment, near 6% of total wells were damaged during their production life, which has serious impacts on the development well pattern, resulting in unbalanced injection-production.
Based on the analysis of the situation and distribution of casing damage in the Tarim Oilfield, which located in northwest of China, was discovered in 1989, Its production formation has unwanted characteristics of high temperature (150°C) and high salinity (250000mg/L), in order to treatment the casing damage wells, a new type of chemical plugging agent named LTTD was synthesized on the basis of LTSD and its resistance to acid, temperature and salinity were carried out by experiments to evaluate the property of new chemical plugging agent.
The plugging strength of LTTD and G-grade cement solidified body in different periods was studied by simulating the actual conditions of Tarim Oilfield, the mechanical properties of adhesive interface between LTTD and G-grade cement under dynamic condition were evaluated and microscopic observation of adhesive interface under dynamic condition were carried out.
The experimental results show that the new plugging agent is characterized by marked improvement of performance and the enhanced resistance to acid, high salinity and high temperature conditions, moreover the formation of "the interpenetrating network structure" with high pressure bearing capacity in short time. In the actual condition of Tarim Oilfield, the plugging strength of LTTD plugging increase with the increase of temperature, which is higher than the strength of G-grade cement, during dynamic process, LTTD plugging is superior to G-grade cement in less amount of dissolution of calcium in hydration process and in better anti-channeling performance. Microscopic observation shows that both the inner and the bonding surfaces of the LTTD blocking agent have compact microstructure, which could effectively avoid the excessive formation of hydration product on bonding interface, and could produce hydration products against erosion, with strong self-healing ability and improve plugging quality.
Field tests show that not only repair casing damage successfully, but also promote the oil production. Therefore, the development of new plugging agent can improve the ultimate recovery of Tarim oilfield. This article provides a type of plugging agent for solving the casing damage and the result may be valuable to develop the similar oilfields.
Prediction of Two-Phase Flow Relative Permeability in Discrete Fractures
Authors: Al-Turki Ali A. , Al-Ghamdi Amell A. , Maucec Marko 
Published: April 2019

Abstract
Considering carbonate oil reservoirs, a rock fracture is a planar-shaped void filled with oil, water, gas and/or rock fines. These fractures vary in scale forming connected and complex networks of fractures. They have an effect on deliverability of fluids depending on their geometrical complexity, extent, matrix-fracture interaction, wettability, and orientation. In fractured reservoir rocks, relative to the rock matrix, fractures form highly permeable flow pathways that dominate fluid flow and transport in the reservoir which might have favorable or non-favorable effects on hydrocarbon production. It is crucial to characterize the fluid flow in the fracture networks to examine the root-cause relationships, the impact on hydrocarbon recovery and quantify the efficiency of enhanced recovery mechanisms.
This work describes the development of a machine learning model for history matching and predicting two-phase relative permeability. Capitalizing on the main principles of the 4th Industrial Revolution (IR 4.0), the development of this model was achieved by training machine learning (ML) algorithms and using advanced predictive data analytics on data collected from lab experiments as input. The model derived from the analysis describes two-phase flow of oil and water in a single discretized fracture taking into account fracture aperture, wall roughness, orientation and, flow rates and direction. It also accommodates fluids and fracture characteristics to match laboratory SCAL experimental of co-current oil and water flow in a mixed-wettability single fracture modeled as narrow gap in a Hele-Shaw cell.
The experimental data exhibit variations in shape and end-points that mainly reflect the effects of fracture aperture, roughness, inclination, and hysteresis effects. This in turn demonstrate the effects of phase interference, saturation changes, and major forces acting on two-phase flow in fractures like capillary and viscous forces.
The empirical relationship showed an acceptable match to the experimentally derived relative permeability in most of the cases as well as good predictive capabilities against the blind tests on other sets of experimental data and numerical simulation models. Having both fracture relative permeability data (describing the fluids flow) and detailed fracture characterization improves our understanding of the reservoir dynamics and fractured network impact on hydrocarbon recovery.
A Case Study for the First Successful Refracturing on Horizontal Well in Tight Volcanic Gas Reservoir in China
Authors: Wang Wenjun , Guo Hongyan , Huang Youquan , Yu Ying , Li Donggang , Li Qinggang , Sui Hongyu 
Published: April 2019

Abstract
This paper introduces the first successful refracturing example of horizontal well in a tight volcanic gas reservoir of Xushen gas field. The well was fractured and put into production in 2008, with the accumulated gas production of 0.64×108 m3. Due to the limited technical conditions of the horizontal well-stage fracturing process at that time, only four fracturing stages have been carried out. the horizontal section of the volcanic gas reservoirs with more than 600 meters of the well was not fractured, leaving a large potential for increasing production. In 2017, based on the fine research of gas reservoirs, the refracturing optimization design, multi-stage perforation, fracturing and commissioning integrated tubular completion and the diagnosis control of complex fractures in fracturing construction, the refracturing job of the well is implemented successfully with a good result.