bluuebunny/crossref_metadata_2025 huggingface dataset:
A Useful Application of Foam for Fast-Tracking Residual Gas Saturation Process and Reducing Leakage Risk During CO2 Injection
Authors: Adebayo Abdulrauf Rasheed
Published: April 2019

Carbon dioxide (CO2) storage in subsurface formations is recognized as the most effective method of permanently sequestering greenhouse gases. However, the possibility of leakage of mobile gases from the storage reservoir is a cause of environmental concern. This study aims to address this concern. A method is presented that can fast-track capillary trapping of gas during gas injection into subsurface geological formations such that a limited amount of free gas is available in case a leakage occur. The method can reduce the time scale of capillary (residual) trapping from decades to weeks. A laboratory experiment indicated that this can be achieved with foam-assisted water alternating gas (FAWAG) injection. In the laboratory setup, capillary trapping of gas was monitored in real time for every successive FAWAG cycle. The trapped gas were stable and remained trapped even after a prolonged water injection. The foaming agents added to the injected water facilitated the increased trapped gas saturation. However, high temperature and salinity significantly reduced the effectiveness of the foam. The type or composition of the injected gas also affect the effectiveness of the foam. The foam is most effective in N2 or N2-rich gas compared to CO2 gas. This was due to the low interfacial tension between the CO2 and the foaming solution. Improvement in foam effectiveness in high temperature high salinity and low IFT environment is much possible as ongoing research works indicate.
Evaluating Cement Integrity through Industry's First LWD Full Range Quantitative Cement Bond Index: A Game Changer in Deepwater Wells
Authors: Saumya Sachit , Singh Juli , Vij Jitesh , Sarkar Sujit , Das Bhaswati , Shedde Preetika
Published: April 2019

Cementing forms an essential part of well construction as it supports the casing and provides hydraulic sealing. Wireline (WL) sonic tools have been providing the cement evaluation (CBL/VDL) for more than 50 years. Quantitative cement evaluation is becoming increasingly important in the industry to verify well integrity and zonal isolation. There has been a growing interest in providing cement bond quality quantitatively with LWD sonic tools owing to its plethora of benefits over wireline logging, such as rig time saving, tool conveyance, less tool eccentering effect and timelapse evaluation. However, there is also an LWD specific challenge that has for long hindered the ability to measure quantitative bond index i.e. drill collar contamination which limits the range of cement bond evaluation with the conventional amplitude-based approach. Deriving a characteristic correlation of attenuation measurement against the bond index was one of the key components to overcoming the limitation of amplitude-based. A new hybrid processing approach combining amplitude and attenuation was established for full-range cement bond evaluation. Schlumberger's LWD multipole sonic Cement Evaluation Service delivers the industry's first quantitative bond index answer product on LWD platform. The quantitative bond index becomes even more critical in offshore and deepwater markets.

This paper discusses, in brief, the technology and associated challenges in delivering industry's first quantitative bond index and showcases the result for one of the deepwater well. A subsequent comparison of LWD multipole sonic cement evaluation results with conventional WL CBL-VDL further corroborates the reliability of the result. The performance of the industry's first LWD bond index derived using LWD multipole sonic from around the globe has demonstrated that it can be expected to show abundant success in expanding the LWD utilization globally
Innovative Mini-DST and Production Evaluation Approach at Challenging HPHT Condition for KeShen Tight Gas Reservoir, a Case Study at Tarim Basin
Authors: Shuai Shichen , Zhang Xinlei , Ma Tengfei , Zhao Yuanliang , Guo Qingbin , Chen Jichao , Fan Zhaoya , Bi Bo , Yang Lei
Published: April 2019

KeShen block at Tarim basin is one of the most important gas reserve for PetroChina. The single well gas production at KeShen area can be as high as million cubic meters per day. However, the complex geology settings of KeShen area lead to significant difficulties on the engineering aspects from the drilling, logging, completion to testing. The reservoir is below a salt layer, having a nature of high pressure and high downhole temperature. Often, the reservoir section must be drilled with 6in hole or even smaller hole size. The combination of challenges: ultra-deep (more than 6000 meters), high temperature, high pressure and slim hole cause the testing operation usually lasts for a few months in time and costs a few million dollars, which is extremely expensive for a land well. Mini-DST with formation testers therefore is considered as an alternative option to providing the necessary fluid, pressure and productivity information.

The main target of the reservoir sand is tight, the permeability is ranging from 0.01 mD to 1mD. Mini-DST operation was not feasible in such challenging environment with the conventional formation testers in the market. A recent introduced new equipment, named 3D radial probe fitting for the slim hole allow a feasibility trial for mini-DST in KeShen area. By the design, the new equipment can work in 6in open hole and provide max. 8000psi pressure drawdown capability. A simulation work has done to confirm this high drawdown can enable the gas flow from the formation to accomplish the testing.

A numerical approach, which integrating all the logging data set and the mini-DST result, is conducted to understanding the production potential of the well. A single well numerical model is created using the logging data, the permeability is carefully calibrated with the mini-DST interpretation, the hydraulic fractures can also be added to the model for feasibility study on well stimulation.

In the last 2 years, multiple wells were selected in KeShen area to do the mini-DST with the new 3D radial probe, the results were very promising. The mini-DST done in the trial wells provide high quality PVT gas samples, high quality pressure transit data for permeability interpretation. The numerical production evaluation also matches very well with the DST result later for comparison. The whole mini-DST operation takes only a few days including conditioning the mud, which is a signification saving on the time and cost. All the cases in these wells will be reviewed and discussed.

With this confirmative result of the work, Mini-DST becomes the first option to test a well at KeShen area if the well condition allowed to reach optimal balance between the data obtained and operation cost.
Successful Execution of a Challenging Well Intervention on First of its Kind Unconventional Dual Completion Well in South East Kuwait Field: A Case Study
Authors: Saffar Ali Hussein , Haddad Hassan , Sindhu Sneh , Gupta Pravind Kumar , Al-Munayes Fahad
Published: April 2019

KOC has been producing oil using dual completions from different pressure regime zones from the same well and South East Kuwait field has many such dual completions wells which are currently being converted from natural flow completion to artificial lift completions. In one of such dual completion naturally producing well, first time in world an artificial lift system - Anchor Pump was installed in Short String (SS) through rigless intervention. Thus project well had un conventional dual completion in the field first of its kind i.e. Sucker Rod Pump (SRP) installed in short string and natural producer through Long String(LS). The well produced for some time through both strings and an intervention by workover rig was required due to high water cut and stuck anchor pump in short string. The paper describes the challenges and initiatives and learnings for safe execution of unconventional dual completion well workover.

Due to combination of natural flow and SRP artificial lift completion, the X-mas tree configuration and associated surface equipment of such well was had several constraints and HSE issues for mobilization of rig and dual production zones with varying pressure regimes have challenges of initial well killing due to plugged short string by stuck anchor pump. The risks were identified during planning stage and risk reduction measures were jointly agreed with Field Development. Various options were explored to minimize risks to ALARP level and subsequently addressed in Work Over Program. The surface equipment constraints were eliminated through rigless works and X-tree configuration were modified to suit deployment of a workover rig. Well process safety principles were applied to accomplish initial well killing in both production zones so as to safely pull out existing dual string completion without any well control issues. An initiative to use sucker rod back off tool, first time and safe back off operation was performed successfully from very close to stuck point.

The existing completion strings were pulled out and further well cleanout and workover program was well cleanout Finally, well was completed with new ESP completion string and successfully production tested. The most important factor in success was proactive planning keeping in view of Process Safety for well control issues and effective communication among the concerned parties.

The initiatives adopted in execution of such a challenging well intervention resulted enhancement in safety to rig crew and Rig operational safety standards in addition to contribution towards cost reduction. Lessons learnt has potential of rig time saving specially during workover of large number of heavy oil wells where stuck sucker rod conditions are very common due to sand invasion in tubing during production.
Tap the Potentials and Reduce the Geological Uncertainties of Mature Complex Fluvial Reservoir: Case Study Redevelopment Plan of D-X Oilfield in Bohai Bay
Authors: He Yifan
Published: April 2019

D-X oilfield implemented an infill adjustment from 2013 to 2015, adding 101 development wells, two central processing platforms and two wellhead platforms.

After the adjustment, the oil field greatly improved the engineering processing capacity, but it had also entered a period of rapid decline. In order to mitigate the decline and improve the recovery rate, 65 adjustment wells were implemented in this oilfield after the first adjustment. Based on the new drilling data and production data, earlier inefficient well management was turned a more efficient well management, where the engineering processing space is fully utilized, the decline of oil field is alleviated, and the development effect is greatly improved.

This this paper expounds how to excavate the potential again after the redevelopment project in large fluvial facies oilfield in Bohai bay, taking this oilfield as an example.
A Novel Technique Applied in Early-Time Pressure Transient Analysis for Fractured Wells with Unpropped Segments
Authors: Luo Le , Cheng Shiqing , Dai Li , Wang Yang , Zhang Jiaosheng , Ma Changlin , Yu Haiyang
Published: April 2019

Propping agents inside hydraulic fractures perform significant role in constructing high-speed flow channel to deliver fluids into wellbore. However, proppant transport in fracture is always influenced by many factors, resulting unpropped fracture. Under such situation, this paper proposes a novel pressure-transient analysis method to better interpreted created fracture properties. The application of signal amplification technology is conducted on pressure transient analysis to deal with non-uniqueness problems. Aiming at transient linear flow, trilinear flow model in fractured wells is further modified and upgraded to characterize unpropped segments. Based on the solutions, this study applied signal amplification technology to extract weak-signals to assist early-time pressure transient analysis. The new type curves regarding with pressure response in partially unpropped fracture is then generated to capture the characteristics of this phenomenon. Subsequently, sensitivity analyses make clear the effects of key parameters on pressure response, which shows the superiorities of the new type curves in pressure transient analysis. The approaches proposed by this paper undoubtly will help solve inverse problems of wells exhibiting long-period linear flow in tight reservoirs.
Generating Geologically Realistic 3D Reservoir Facies Models Using Deep Learning of Sedimentary Architecture with Generative Adversarial Networks
Authors: Zhang Tuanfeng , Tilke Peter , Dupont Emilien , Zhu Lingchen , Liang Lin , Bailey William
Published: April 2019

This paper proposes a novel approach for generating 3-dimensional complex geological facies models based on deep generative models. It can reproduce a wide range of conceptual geological models while possessing the flexibility necessary to honor constraints such as well data. Compared with existing geostatistics-based modeling methods, our approach produces realistic subsurface facies architecture in 3D using a state-of-the-art deep learning method called Generative Adversarial Networks (GANs). GANs couple a generator with a discriminator and each uses a deep Convolutional Neural Network (CNN). The networks are trained in an adversarial manner until the generator can create "fake" images that the discriminator cannot distinguish from "real" images. We extend the original GAN approach to 3D geological modeling at the reservoir scale. The GANs are trained using a library of 3D facies models. Once the GANs have been trained, they can generate a variety of geologically realistic facies models constrained by well data interpretations. This geomodelling approach using GANs has been tested on models of both complex fluvial depositional systems and carbonate reservoirs that exhibit progradational and aggradational trends. The results demonstrate that this deep learning-driven modeling approach can capture more realistic facies architectures and associations than existing geostatistical modeling methods, which often fail to reproduce heterogeneous nonstationary sedimentary facies with apparent depositional trend.
Experimental Investigation of the Impact of Modified Nano Clay on the Rheology of Oil Well Cement Slurry
Authors: Murtaza Mobeen , Mahmoud Mohamed , Elkatatny Salaheldin , Majed Abdulaziz Al , Chen Weiqing , Jamaluddin Abul
Published: April 2019

In cementing operations of deep oil and gas wells, long term integrity of the well is highly dependent on the cement sheath. Obtaining success rate in cementing operations has been subjected to a myriad of challenges, as drilling into deeper, high pressure/high temperature horizons is done. To gain long term integrity of cement sheath, a successful placement of cement slurry plays a pivotal role. So, the design of suitable rheological properties helps characterize the cement pumpability, mixability, and displacement rates for adequate removal of mud. So, the design of cement slurry for HPHT and deviated wells has become a complex task. Recently employing nano-materials in improved oil recovery, designing of drilling fluids as well as hydrocarbon well cementing has been the focus of many studies. The intrinsic characteristics of being smaller in size, while at the same time providing a larger surface area, nanomaterials can prove to be a game-changer for the challenges faced in HPHT cementing. This paper reproduces the outcomes of an investigational study conducted to determine the effect of nanoclay as an additive on rheological properties of Type-G cement slurry under various temperature conditions. Nano-clay with Class G cement in two different concentrations 1% and 2% by weight of cement, mixed and tested under different temperature conditions (37°C, 50°C, 60°C & 80 °C). Additionally, nano-clay based cement mixtures were prepared by substituting cement with 1%, 2% and 3% of nano-clay by weight of cement(BWOC), and admixed with silica flour, along with various chemical admixtures. American Petroleum Institute (API) standard-10B was followed to condition the slurry at predetermined temperature, while the slurry was under atmospheric pressure. This conditioning was followed by the measurement of rheological properties. Results of this investigation demonstrate that incorporation of nano-clay advances the rheology of prepared cement slurry that could aid in mud-displacement and anti-settling as per the requirements.
Artificial Lift Methods Optimising and Selecting Based on Big Data Analysis Technology
Authors: Shi Junfeng , Chen Shiwen , Zhang Xishun , Zhao Ruidong , Liu Zhaoyu , Liu Meng , Zhang Na , Sun Dakui
Published: April 2019

The best artificial lifting method for a well is to lifting more with less during the whole life cycle, however, it is difficult to select the best method because there are many factors affecting the choice of artificial lifting methods and most factors cannot be described with mathematical models. At present, the selection mainly depends on experts’ experience, which results in many incorrect decisions and lead to huge economic loss. In China, there are a large number of artificial lifting wells, and the large amount of data generated by the wells is of great value, which can be used to select the best artificial lifting method for different type of oil wells. This paper selects 11 parameters, including well fluid characteristics, fluid production capacity, well trajectory, pump depth, pump efficiency, pump inspection period, and maintenance cost per year as influence factors. About 40,000 artificial lifting wells of CNPC were selected as the big data analysis sample initially. As not all the wells are good samples, an effect evaluation function is established by taking pump efficiency, power consumption with lifting per ton liquid 100m, annual operating maintenance cost into account, then the samples are selected further according to the value of effect evaluation function, which ensured all the samples participated in machine learning are good samples. A deep recurrent neural network was established which can select the best artificial lifting method through deep learning. Experimental results showed that the neural network model had fast convergence and high prediction accuracy. With the application of this model, artificial lifting method selecting and effect analysis have been conducted for more than 5,000 oil wells of CNPC with different reservoir characteristics, different wellbore structures and different fluid characteristics. The coincidence rate between calculation results of this model and actual production situation is 90.56%. Big data analysis provides a reliable, practical and intelligent method for optimizing and selecting artificial lift.
Drilling Dynamics Measurements on Positive Displacement Motors PDM Enhance Performances and Reliability
Authors: Li Fei , Neelgund Rohan V. , Smith David L. , Blackman Wesley
Published: April 2019

Positive displacement motors (PDMs) have been extensively utilized in the North America unconventional market. PDMs are frequently run with aggressive parameters in challenging drilling environments to increase drilling performance. Because PDMs are typically rental equipment, there is often not much information givento the equipment owners when tools are returned after use. This situation limits the opportunities for failure investigation, preventive maintenance, and tool design optimization. Furthermore, measurement-while-drilling (MWD) tools in PDM bottom hole assemblies (BHAs)only measure dynamics of the drill collars, considerably above the motor, often without sufficient resolution to understand adverse drilling dynamics and to design remedial actions for the operations.

A dynamics measurement data recorder was developed and introduced for this type of operation. The data recorder is a small, low-cost, and battery-powered device. It is installed in the rotor catch of a conventional PDM in such a way that no additional component is added to the BHA length. The recorder is fitted with a triaxial vibration accelerometer, a triaxial shock accelerometer, a gyroscope and a temperature sensor. The recorder can log data over a full PDM operation cycle, including shipment, rig-side handling, and downhole operation.

The data recorder has been deployed in North American land operations since 2016. One case study is presented, and the data analysis showed that PDM operation cycles were captured from the installation of the recorder in maintenance bases to the return of the tools. Torsional vibrations and stick-slip generated by mudmotors during sliding phases were effectively captured. In several cases, bit dull grade conditions were correlated with recorded drilling dynamics data as part of failure analyses to understand the root cause of the problem.
A Dynamic Characterization Approach for a Complex Naturally Fractured Reservoir
Authors: Alcantara Ricardo , Santiago Luis Humberto , Fuentes Gorgonio , Garcia Hugo , Romero Pablo , López Pedro , Angulo Blanca , Martinez Maria Isabel
Published: April 2019

The Naturally Fractured Reservoirs (NFR) constitute a challenge for the oil industry due to its importance in hydrocarbon production and the technical complexity they represent, because well’s productivity in carbonated formations is influenced by fracture systems that govern the fluids motion within reservoirs.

This approach is oriented to the analysis of a very complex NFR, where we show the results obtained through a dynamic characterization methodology focused on new opportunities in a High Pressure-High Temperature (HP-HT) coastal mature oilfield with high water cut production. The proposed methodology is based on a full analysis starting from the pressure-production historical data, fluids properties, dual-porosity material balance, a detailed static model update (petrophysics, core analysis, petrography, fracture analysis, sedimentology-diagenesis and structural geology), flow units discretization, Water-Oil Contact (WOC) advance monitoring in each block, Pressure Transient Analysis (PTA) (determination of preferential flow direction and interference), and Rate Transient Analysis (RTA).

This methodology allowed to determine the real Original Oil in Place (OOIP) and the proper recovery factor according to the type of NFR and its characteristics, to detect different WOC’s for each block that were hydraulically connected to each other but with a different dynamic behavior among them, the detection of heterogeneities, facies changes and faults that originally were not mapped, sweet spots location, better distribution of the petrophysical properties, fracture analysis, static model reinterpretation based on the dynamic behavior, reservoir connectivity analysis (among blocks) and the generation of improved production forecasts based on an exploitation strategy especially designed for the current conditions and needs of the field; all of this contributed to have a better understanding of the reservoir and a good numerical simulation model.
Research of Formation Protection Technology in Complex Fault Block Oilfield
Authors: Fan Songlin , Wang Xiaofang , Dong Jun , You Qiuyan , Yang Xiaochun , Zhao Junfeng
Published: April 2019

Dagang Oilfield is a part of oil-gas reservoir with various reservoir types, broken fault block, high heterogeneity and complex geological situations. For example, in low pressure and high permeability reservoirs, permeability is higher than 2000 mD and pressure coefficient is less than 0.5. The salinity of formation water in low permeability reservoir is as high as 30000 mg/L, and the pour point of crude oil is as high as 40 °C. The statistics show that the average recovery time of the well yield after remedial work is over 7 days, and the average recovery rate of the well yield is less than 87% in Dagang Oilfield, which have an influence on the stable production and the benefit development of the oilfield. The problem above has not been effectively resolved for a long time because of the factors of technology and cost. In this paper, a series of low cost formation protection technology were developed. First, the low-cost nitrogen microbubble temporary blocking technology, which can block 2 mm aperture, was developed by improving preparation technology of nitrogen microbubble working fluid and adding degradable temporary blocking material. Second, the formation protection for complex low-permeability reservoirs was developed by enhancing the temperature of workover fluid and adding the high efficiency surfactants. The results show that the temperature of workover fluid increases by 20-50 °C. Finally, the low-cost workover operation technology with formation protection was developed. The cost can be reduced more than 50% while protecting the formation. So far, the all technologies were successfully applied in 2135 wells. After the application of technology, the average recovery time of the well yield is 3.5 days, the average recovery rate of the well yield is 96%, and the total production loss is 15.7 ° 104t. The problem of the formation pollution during the workover has been effectively resolved, which provides technical support for the production stability of complex fault block oilfield.
Capillary Pressure Corrections, Quality Control and Curve Fitting Workflow
Authors: Al-Bulushi Nabil , Kraishan Ghazi , Hursan Gabor
Published: April 2019

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

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

Hydraulic 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

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

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

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

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.