bluuebunny/crossref_metadata_2025_split huggingface dataset:
Technology of Fire Flooding Process Control: Application to Fire Flooding in a Deep and Thick Heavy Oil Reservoir in China
Authors: Feng Tian , Wu Yi , Hu Changhao , Gong Yuning , Song Yang 
Published: October 2018

Abstract
Fire flooding process has been applied to the thick and deep heavy oil reservoirs G3618 and G3 in Liaohe oil field in China. Currently, there are two main operating issues: the serious combustion front gravity override, and the low areal sweep efficiency. Thus, research of process control is conducted for the entire project area, each layer, and also individual well patterns, with the objective of achieving better vertical and areal conformance.
G3 and G3618 have average thickness of 68.6m and 103.8m, with similar depth of 1600m. Three major process control methods are used: using vertical-horizontal well configuration, reconfiguring to line drive plus vertical-horizontal hybrid configuration, and air injecting at top positions. We establish geological model with focus on interlayer vertical communications. Through reservoir simulation and field data analysis, we test potential benefits of using horizontal producers. We further compare the different performances of line drive and pattern flood in G3618 and G3. Finally, with G3618 having 20 degree dip angle, we test the effect of air injection at higher elevations through simulations and laboratory experiments.
First, we have found 2m as the critical thickness for shale interlayer barriers to prevent vertical communications and to minimize gravity override. The combination of vertical and horizontal wells shows great improvements in conformance, since the horizontal producer at bottom of the reservoir could more effectively drain the reservoir. Second, we find line drive is more effective than pattern flood with recovery improvement of around 10%, proven by reservoir simulations and field production analysis. Third, if we inject from top, we benefit from high recovery of gravity drainage, with much oil accumulated at reservoir bottom. We recommend conducting top injection when reservoir thickness is above the critical value of 20m. Finally, we have establish line drive fire flooding configuration in G3 reservoir with air injectors located at top positions of the reservoir, which causes oil production rate to increase by about 80% since initiating these adjustments. For G3618 reservoir, we have also reconfigured the well patterns to line drive with air injectors at elevated locations, with daily production rate increased by 30%.
Through field experience, we have found that controlling combustion front override and improving areal sweep efficiency are great technical challenges for fire flooding process. We demonstrate that measures of implementing line drive, injecting at the top while producing at deeper locations, and configuration of vertical injectors and horizontal producers have already made significant improvements in fire flooding production performance in Liaohe oil field in China.
Deep Learning Convolutional Neural Networks to Predict Porous Media Properties
Authors: Alqahtani Naif , Armstrong Ryan T. , Mostaghimi Peyman 
Published: October 2018

Abstract
Digital rocks obtained from high-resolution micro-computed tomography (micro-CT) imaging has quickly emerged as a powerful tool for studying pore-scale transport phenomena in petroleum engineering. In such frameworks, digital rock analysis usually carries the problematic aspect of segmenting greyscale images into different phases for quantifying many physical properties. Fine pore structures, such as small rock fissures, are usually lost during segmentation. In addition, user bias in this process can lead to significantly different results. An alternative approach based on deep learning is proposed. Convolutional Neural Networks (CNN) are utilized to rapidly predict several porous media properties from 2D greyscale micro-computed tomography images in a supervised learning frame. A dataset of greyscale micro-CT images of three different sandstones species is prepared for this study. The image dataset is segmented, and pore networks are extracted to compute porosity, coordination number, and average pore size for training and validating our model predictions. The greyscale images (input) and the computed properties (output) are uploaded to a deep neural network for training and validation in an end-to-end regression scheme. Overall, our model estimates porosity, coordination number, and average pore size with an average error of 0.05, 0.17, and 1.8μm, respectively. Training wall-time and prediction error analysis are also discussed. This is a first step to use artificial intelligence and machine learning methods for the robust prediction of porous media properties from unprocessed image-driven data.
Dynamic Modelling of Walloon Coal Measures: An Unsavoury Cocktail of Reservoir Variability, Mismatched Resolutions, and Unreasonable Expectations
Authors: Cardwell Joshua 
Published: October 2018

Abstract
A full-field dynamic simulation model has traditionally been seen as the benchmark for assimilating all available static and dynamic data to develop robust production forecasts. Santos’ experience modelling the Walloon Coal Measures in its Surat Basin acreage has shown that the performance of individual wells producing from this CSG reservoir is governed by reservoir variability at a fine-scale. This presents a fundamental challenge in developing full-field dynamic models that can accurately describe and predict production performance down to the scale of individual coal seams.
Current Queensland CSG projects have focussed on the most prospective acreage, however as subsequent developments move to more marginal areas a greater understanding of the subsurface will be required for optimum development. The target formations will increase in geological complexity, such as Santos’ Surat Basin acreage on the edge of the CSG fairway. Here wells produce from a greater number of distinct coal reservoir units, and how these reservoir units are structured and relate to each other governs reservoir connectivity and defines long-term production performance. Each reservoir unit is comprised of multiple coal plies, all with their own unique maceral distribution and cleating characteristics. These fine-scale properties define the reservoir's dynamic behaviour, and can be impossible to upscale such that these characteristics are preserved at a coarse scale. Consequently, accurately modelling individual well performance will require a fine-scale model to capture and characterise this variability.
In development areas where the quantity and quality of reservoir data gathered from exploration and appraisal is sparsely populated, these fine-scale models will need to be populated geostatistically. Without model-scale appropriate control data from production and pressure measurement in the development wells to provide constraints however, a probabilistic model will not accurately define fine-scale behaviour of specific reservoir units. These data requirements can help shape the appraisal scope for new areas and define an appropriate level of surveillance for producing assets.
Traditional full-field dynamic modelling has fundamental limitations for interrogating complex unconventional CSG reservoirs at a fine scale. Because of this, alternative workflows are required to answer the subsurface questions necessary to develop CSG assets such as the Surat Basin effectively. This paper details a selection of workflows explored to address this pragmatically, as well as their limitations and associated data requirements. This will also assist in identifying data gaps needed for optimum reservoir management and to aid in the development of these challenging CSG reservoirs.
Prediction of In-Situ Stresses and Pore Pressure in a Shale Gas Reservoir Subject to Finite Fault Slip
Authors: Lin Botao , Jin Yan , Chen Yun 
Published: October 2018

Abstract
The shale reservoirs in Sichuan Basin, west China, are located in a geological region plagued by frequent seismic activities. Fault slips can induce significant time-dependent stress and pore pressure changes in those reservoirs. In order to properly drill a stable wellbore or perform hydraulic fracturing, it is desired to evaluate the state of in-situ stresses and pore pressure after slip of faults at relatively close distances to the wellbore. The surrounding solid matrix was assumed to be linear elastic and fluid infiltrated. First, the in-situ stresses of a horizontal rectangular fault subject to shear dislocations along its edges were analyzed based on poroelasticity. Secondly, the solutions were projected to a fault having specific strike and dip angles. The direction and magnitude of fault slip were recorded from the three-dimensional seismic profile. The pore pressure was calculated based on the predicted stresses using Skempton's coefficients. Finally, the complete stress and pressure fields were derived from superposition of the solutions with the static analysis results from using the finite element (FE) method on the continuum reservoir. It was found that the mean normal stress σ and octahedral shear stress τ induced by a finite fault slip exhibit antisymmetric patterns about each fault edge if the dip angle φ is zero, and decrease rapidly with distance to the fault plane. The contours gradually distort with an increase of φ while being much less sensitive to the strike angle θ. In addition, the magnitude and extent of the induced stress or pressure enhance with slip magnitudes. Implementing the poroelastic approach to a shale reservoir in Weiyuan region of Sichuan province in southwest China disclosed that the predicted maximum and minimum stress curves match the measured data satisfactorily. Meanwhile, the induced pore pressure is significantly dependent on the Skempton's B coefficients of the shale matrix. In summary, this study provides a poroelastic means to quantitatively predict the 3D in-situ stress and pore pressure fields in a shale reservoir with finite faults, which have reservoir stratigraphy as well as fault dimension and slip obtained from interpretation of the seismic profile.
Comparing Carbon Intensity of Unconventional and Asia Pacific Oil Production
Authors: Meehan D. Nathan , El-Houjeiri Hassan , Rutherford Jeffrey S. 
Published: October 2018

Abstract
Carbon intensity (CI) of oil and gas production varies widely across global oil plays. Life cycle extraction from certain unconventional plays (e.g., tar sands) have the highest CIs but even many North American shale plays have high CI. Flaring and venting of associated or non-associated natural gas dramatically increases CI. This paper applies peer-reviewed processes across broad averages of shale activity in North America and compares them with CI in countries in the Asia Pacific region. Ways to lower the carbon intensity in both areas are discussed.
We perform well-to-refinery calculations of CI for major unconventional oil plays in North America and conventional plays in Asia Pacific. This approach accounts for emissions from exploration, drilling, production, processing, and transportation. The analysis tool is an open-source engineering-based model called Oil Production Greenhouse Gas Emissions Estimator (OPGEE). OPGEE makes estimates of emissions accounting using up to 50 parameters for each modeled field. This model was developed at Stanford University. Data sources include government sources, technical papers, satellite observations, and commercial databases.
Applied globally, OPGEE estimates show highest values in areas with extensive flaring of natural gas and very heavy crude oils - heavy oils require large energy inputs (e.g., steam flooding) and/or the use of light hydrocarbon diluents for transportation offset. A few other major areas included for reference. Examples illustrate how OPGEE can be used to evaluate the CI of public policy actions. A sensitivity analysis to flaring volumes illustrates these impacts, and further sensitivity analyses to pad drilling and improving well performance show CI impacts associated with hydraulic fracturing.
Unconventional production, especially from light tight oil is the most significant new source of fossil fuels in the last decade. Under a wide variety of carbon constraints, oil usage will continue for many decades and increase in the near term. Operators, governments, and regulators need to be able to avoid "locking in" development of suboptimal resources and instead provide incentives for shale operators to manage resources sustainably. This approach provides quantitative measures of such actions. Oil producers must prepare by eliminating development of marginal projects, elimination of flaring and venting, optimizing hydraulic fracture treatments, using improved recovery methods (e.g., enhanced oil recovery using anthropogenic CO2), reducing energy use, and eliminating unnecessary gas waste.
Alleviating the Solids Issue in Surat Basin CSG Wells
Authors: Kalinin Daniel , Choo Daryl , Watling Ashley , Liu Hai , Kong Teng Ling , Soo Hui Gog 
Published: October 2018

Abstract
A system for reducing solids production in Surat basin coal seam gas (CSG) wells was developed in the laboratory and tested in the laboratory and field trials.
Several thousand CSG wells were completed in Surat basin in eastern Australia using what was considered an economic method at a time - an open hole with a predrilled liner.
Although the majority of the wells are meeting production expectations, a many wells are producing a substantial amount of solids originating from an interburden rock representing approximately 90% of completed interval length and comprising mudstones, sandstones, and siltstones rich in illite/smectite and other water-sensitive clays. Relatively fresh water, with total dissolved solids (TDS) of approximately 4000 to 7000 mg/l, produced from multiple thin coal seams during dewatering and production phases is causing the interburden rock to swell or disintegrate. Prolific wells with high water rates or high gas velocity are capable of carrying solids to the surface where the solids are deposited in separators, flowlines, and water-treatment settling ponds. Higher solids concentration on lower-rate wells are causing issues with positive cavity pumps (PCP), the artificial lift method of choice in CSG wells. Pump intake plugging with solids, excessive torque and rotation seizure, and wear of tubing/rod strings are frequent causes of workovers and shorter-than-expected pump run-life. Some wells are able to flow freely; however, an extra monitoring program is required to ensure wellheads are not suffering from solids-induced erosion.
Recompletion of the wells is not considered practical at this stage because pre-perforated joints form an integral part of the 5 ½-in. or 7-in. casing string, which is cemented above the Walloons subgroup coal seams. An external casing packer (ECP) is often used. Some coal seams were underreamed, thus further complicating recompletion. Plugging existing wells and drilling a pair of wells using same surface location and infrastructure have been considered.
A chemical wellbore stabilization solution been developed to alleviate/stop solids production from the interburden rock. The treatment comprises two fluids separated by a spacer that contains clay stabilizer that is typically 3 to 7% KCl, the same as drilling mud base. Proprietary surfactant reduces the possibility of coal damage. Regained permeability testing performed using crushed and sieved coal pack plugs indicated a low level of damage. The wellbore stabilization system could be energized/foamed to reduce hydrostatic pressure and increase compressibility, hence increasing the chance of contacting rock surface in an enlarged wellbore.
The Application of Flexible Coiled Composite Pipe in Onshore Oilfields in China
Authors: Ming Eryang , Li Tao , Li Yiliang , Pei Xiaohan , Hao Zhongxian , Guo Tong 
Published: October 2018

Abstract
In recent years, the flexible coiled composite pipe (FCCP) has developed rapidly in China. Because of its merit about chemical inertness, it has been introduced to onshore oilfields to endurance some severe situations, such as serving as tubing in corrosive and waxy oil wells, as tubing in scaling water injection wells or as surface gathering pipelines, especially suitable for mountainous areas. This paper will introduce the development status of FCCP in different applications.
According to our research and development, for FCCP structure manufacture, there are two main technical routes in China, non-adhesive pipe and adhesive pipe. These two kinds of pipe meet the merits of FCCP, however, there are some differences in technical parameters. Obviously, non-adhesive pipe has smaller bending radius, but the integrity of adhesive pipe is better which is good for fitting installation. In this technical stage, the FCCP has been applied in surface gathering system, general water injection system and rodless artificial lift system.
For surface gathering system, this is the most mature application of this technology. It has been laid over 30,000 kilometers. Compared with steel pipe, the equipment of FCCP is simple and high laying efficiency. For general water injection system, the FCCP replaces steel pipe by high working efficiency and long endurance. It has been applied more than 80 wells. For rodless artificial lift system, there are almost 60 wells applied FCCP. It is the severest running condition for FCCP with high temperature, high wellbore pressure and high varies suspension force. This application reveals the advancement of FCCP by twining cables inside the pipe body and adding functions of real-time monitoring and heating. Two typical applications are serving as tubing in cold heavy oil production and acid gas corrosion oil well. The application of FCCP has made great progress. But there are several key issues that need to be resolved in the future research. First, there is lack of post evaluation of performance. Second, the limit of material working temperature shrinks the application scope. Third, the external pressure resistance is limited.
This paper shows the applications of flexible coiled composite pipe in onshore oilfields of China in the past 5 years, including a summary of technical experience, and proposing the goal of further research.
Case Study for Performance Benefits of Cased-Hole Logging in Coal Bed Methane CBM
Authors: Mastin Stephen , Pfahl Matthew , Jukes Rachael 
Published: October 2018

Abstract
This paper presents a case study review of the performance benefits of a 66 well Coal Bed Methane (CBM) development program whereby cased-hole (CH) logging was introduced as a substitute for open-hole (OH) logging. This paper demonstrates how the reduction in OH logging requirements improved time and cost performance and reduced risk exposure while maintaining suitable data quality.
The approach was based on utilizing existing offset well data and three-dimensional (3D) seismic data to substitute OH density logging for CH density logging. Therefore reducing critical path time on the drilling rig and risk exposure with wireline logging tools in an OH environment. A qualitative and quantitative approach to review rig performance and cost benefits was subsequently undertaken.
The density log was of key importance as it is used to define net coal thickness in CBM reservoirs. Current CH density logging typically results in the reduction of log resolution and accuracy which limits the ability to resolve thinner coal seams. The loss of coal definition has the potential to result in the under-estimation of net coal for reserves purposes, impact static modelling and possibly negatively impact fracture stimulation decisions.
The 66 well development program provided a suitable data set to quantify the performance benefits of a combined CH and OH evaluation program. The transition to CH density logs removes online evaluation activities during the drilling operation. This provides a direct time and associated spread cost saving. In addition, unsuccessful OH logs were replaced with CH density logs when hole conditions presented higher likelihood of unproductive and high risk operations (tight hole/fishing). The campaigning of CH logging operations further optimized both wireline and operating company resources and time. The CH density logs provided suitable data to adequately identify coal targets in order to stimulate and complete the wellbore. The reduction in log resolution and coal identification was overcome by developing 'optimized' density cut-offs based on a calibration study with OH density wireline data.
This case study supports the use of CH density logs in lieu of OH density logs where feasible for CBM reservoirs. It demonstrates the operational optimizations and cost savings by conducting wireline logging operations offline while also reducing risk exposure to down hole issues.
Using Machine Learning to Predict Lost Circulation in the Rumaila Field, Iraq
Authors: Al-Hameedi Abo Taleb , Alkinani Husam H. , Dunn-Norman Shari , Flori Ralph E. , Hilgedick Steven A. , Amer Ahmed S. , Alsaba Mortadha T. 
Published: October 2018

Abstract
Lost circulation costs are a significant expense in drilling oil and gas wells. Drilling anywhere in the Rumaila field, one the world's largest oilfields, requires penetrating the Dammam formation, which is notorious for lost circulation issues and thus a great source of information on lost circulation events.
This paper presents a new, more precise model to predict lost circulation volumes, ECD and ROP in the Dammam formation. A larger data set, more systematic statistical approach, and a machine learning algorithm have produced statistical models that give a better prediction of the lost circulation volumes, ECD, and ROP than the previous models for events. This paper presents the new model, validates the key elements impacting lost circulation in the Dammam formation, and compares the predicted outcomes to those from the older model.
The work previously in the literature provided a platform for predicting the severity of lost circulation incidents in the Dammam formation. Using the new models, the predictions closely track actual field incidents of lost circulation. When new lost circulation events were compared with predictions from the old and new models, the new model presented a much tighter prediction of events.
Three equations for optimizing operations were developed from these models focusing on the elements that have the highest degree of impact. The total flow area of the nozzles was determined to be a significant factor in the ROP model indicating that nozzle size should be chosen carefully to achieve optimal ROP.
Good modeling of projected lost circulation events can assist in evaluating the effectiveness of new treatments for lost circulation. The Dammam formation is a significant source of lost circulation in a major oilfield and warrants evaluation of the effectiveness of lost circulation treatments. These techniques can be applied to other fields and formations to better understand the economic impact of lost circulation and evaluate the effectiveness of various lost circulation mitigation efforts.