bluuebunny/crossref_metadata_2025 huggingface dataset:
Promising Pathways to Lower Atmospheric Carbon Without Sacrificing the Petroleum Advantage
Authors: Gupta Subodh Chandra
Published: September 2019

The traditional advantage of petroleum-based transport fuels of unmatched energy-density and affordability is diluted with the requirement to lower atmospheric carbon. However, despite a significant R&D effort and investment over the last three decades, humanity is still looking for carbon neutral alternatives to petroleum that can be commercially viable. This paper presents meaningful novel approaches to deal with carbon abatement utilizing petroleum that have a better chance to succeed in fulfilling the underlying techno-economic desirables.

While the multi-directional work performed in the past on the subject has informed us on a variety of related topics, going forward the society can benefit from a systematic approach to solving atmospheric CO2 problem building on the petroleum advantage. A framework formulating the challenge in terms of techno-economic and environmental requirements is presented that narrows down further work to only meaningful and promising leads. With this framework in mind a few specific pathways are proposed that naturally hold the desired traits if certain conditions are met. These conditions in turn define specific objectives of the subsequent developmental work. While it is premature to suggest any of these will develop into a commercially viable pragmatic method, due to the underlying criteria they hold a better chance to be successful. The presented pathways using advances in electro-chemistry, nanoscience, rational design, and other areas range from (a) mimicking natural fixation of CO2 as in plants to produce tailored polysaccharides or food, to (b) converting CO2 to substances such as carboxylic acids for easy and cost effective sequestration, to (c) changing the way petroleum fuel is used in internal combustion engines to alter the exit state of oxidation of carbon so that the waste product is easily and economically captured compared to the conventional waste product - CO2.

One outcome from the framework results in collapse of the economic models and associated technical approaches that aim to convert CO2 to sellable products, owing mainly to the volume of the global GHG challenge. On the other hand, a common element in the proposed promising leads is to deal with the problem of carbon abatement as an added step with an associated cost. The lower this cost, the less diluted the petroleum-advantage. In this context the framework also points to a range of relative costs that the carbon abatement approaches have to work within to retain the petroleum advantage.

The outlined technical approaches of carbon abatement are not previously discussed in the literature and hold the promise to help combat the global GHG challenge in a more practical and significant way.
Nanopaint-Aided Electromagnetic Pigging in Pipelines and Production Tubing
Authors: Wang Ningyu , Prodanovic Maša , Daigle Hugh
Published: September 2019

Precipitation and deposition of paraffin wax and hydrates is a major concern for hydrocarbon transport in pipelines, tiebacks, and other production tubing in cold environments. Traditionally, chemical, mechanical, and thermal methods are used to mitigate the deposition at the expense of production interruption, complex maintenance, costs, and environmental hazards.

This paper studies the potential of nanopaint-aided electromagnetic pigging. This process has potentially low production impact, simple maintenance, low energy cost, and no chemical expense or hazards. The electromagnetic pig contains an induction coil that emits an alternating magnetic field. The alternating magnetic field induces heat in the nanopaint coating (i.e. coating with embedded paramagnetic nanoparticles) on the pipeline's inner wall and in the pipeline wall itself. The heat then melts and peels off the wax and hydrates adhering to the pipeline, allowing the hydrocarbon to carry them away.

We analyze the heating effectiveness and efficiency of electromagnetic pigging. The heating effectiveness is measured by the maximum pigging speed that allows deposit removal. The heating efficiency is measured by the ratio of the heat received by the wax over the total emitted electromagnetic energy, which we define as the pig induction factor.

Based on our numerical model, we compare the pig induction factor for different coil designs, different hydrocarbon flow rates, and different pig traveling speeds. We find that slower pig speed generally improves the pigging performance, that shorter solenoids with larger radius have higher efficiency, and that the oil flow does not considerably affect the process. We re-evaluate the maximum pig speed defined by the static pig model and confirm that a solenoid with larger radius allows higher pig speed.

We investigate the potential of a novel, low-maintenance electromagnetic pigging method that poses minimal interruption to production. This investigation is a basis for a new technology that stems from initial experimental investigation done by our collaborators. We here provide parameters for pig design and pigging protocol optimization, and will put them in practice in our future lab experiments.
Mobilizing Tight Matrix Oil through CO2 Huff-N-Puff Method in a Fractured Sandstone Rock: A Case Study
Authors: Wei Bing , Zhang Xiang , Gao Ke , Li Yibo , Pu Wanfen
Published: September 2019

CO2 injection, either miscible or immiscible, has been recognized as a promising method to enhance oil production for tight reservoirs, with major projects in progress worldwide. This work targeted a tight sandstone reservoir in China, located in the Lucaogou formation of Jimsar sag, Junggar Basin. CO2 injection using huff-puff method was planned to stimulate the oil production because of the rapidly declining productivity of the existing horizontal wells. Although some laboratory works have been conducted for this site, there still lacks the knowledge of mobilizing process of the matrix oil when natural fractures are present. Herein, we present an experimental study of CO2 huff-n-puff in a fractured sandstone rock with the primary objective of elucidating the oil recovery dynamics in different phases under reservoir conditions. The results indicated that the oil recovery rate rapidly decreased with cycle numbers and CO2 huff-n-puff primarily recovered the oil in the large matrix pores. After three cycles, an incremential 32.2% of the original oil-in-place (OOIP) was produced. Based on the dynamics of oil mobilization, the main-determining-forces (MDFs) in this process were re-defined. CO2 displacement, CO2-oil interaction driven by diffusion, and depressurization dominated the first cycle, whereas from the second cycle the first two forces became insignificant. This implied that the soaking phase could be minimized or even eliminated from the second cycle in order to reduce the shut-in time in field application.
A Hybrid Modeling Approach to Production Control Optimization Using Dynamic Mode Decomposition
Authors: Zalavadia Hardikkumar , Sankaran Sathish , Kara Mustafa , Sun Wenyue , Gildin Eduardo
Published: September 2019

Model-based field development planning and optimization often require computationally intensive reservoir simulations, where the models need to be run several times in the context of input uncertainty or seeking optimal results. Reduced Order Modeling (ROM) methods are a class of techniques that are applied to reservoir simulation to reduce model complexity and speed up computations, especially for large scale or complex models that may be quite useful for such optimization problems. While intrusive ROM methods (such as proper orthogonal decomposition (POD) and its extensions, trajectory piece-wise linearization (TPWL), Discrete Empirical Interpolation Method (DEIM) etc.) have been proposed for application to reservoir simulation problems, these remain inaccessible or unusable for a large number of practical applications that use commercial simulators.

In this paper, we describe a novel application of a non-intrusive ROM method, namely dynamic mode decomposition (DMD). We specifically look at reducing the time complexity involved in well control optimization problem, using a variant of DMD called DMDc (DMD with control). We propose a workflow using a training dataset of the wells and predict the state solution (pressure and saturation) for a new set of bottomhole pressure profiles encountered during the optimization runs. We use a novel strategy to select the basis dimensions to prevent unstable solutions. Since the objective function of the optimization problem is usually based on fluid production profiles, we propose a strategy to predict the fluid production rates from the predicted states from DMDc using machine learning techniques. The features for this machine learning problem are designed based on the physics of fluid flow through well perforations, which result in very accurate rate predictions. We compare the proposed methodology using another variant of DMD called ioDMD (input-ouput DMD) for system identification to predict output production flow rates.

The methodology is demonstrated on a benchmark case and a Gulf of Mexico deepwater field that shows significant time reduction in production control optimization problem with about 30 – 40 times speedup using the proposed DMDc workflow as compared to fine scale simulations, while preserving the accuracy of the solutions. The proposed "non-intrusive" method in this paper to reduce model complexity can substantially increase the range of application of ROM methods for practical field development and reservoir management.
High-Resolution Ultrasonic Borehole Imaging Enhances Reservoir Evaluation in Oil-Based Muds
Authors: Li Peng , Lee Jonathan , Taher Ahmed , Coates Richard , Marlow Rodney
Published: September 2019

Obtaining high-resolution borehole images in oil-based mud (OBM) from logging-while-drilling (LWD) tools has been made possible through the recent development of ultrasonic imaging technologies. High-resolution acoustic impedance images enable reservoir evaluation through the identification of faults and fractures, bedding and laminations, and assessment of rock fabric. This paper presents examples of high-resolution images from a 4¾-in. ultrasonic imaging tool in OBM applications and discusses their value in assessing reservoir quality.

This paper provides details of field trials of an LWD ultrasonic imaging tool for use in boreholes ranging from 5¾ to 6¾ in. High-resolution images detailing both borehole caliper and acoustic impedance in both vertical and horizontal wellbores are shown, illustrating the high level of formation evaluation now available when OBM is used. The methodology used to address the impact of tool motion on the impedance images will also be covered. The value of real-time data on borehole stability assessment will be discussed, along with additional applications made possible from the real-time data, such as wellbore placement enhancement.

Both real-time and recorded data from field trials show the potential applications for the ultrasonic imaging tool. High-resolution impedance images covering different formations and lithologies show bedding planes and laminations and enable the calculation of stratigraphic dip, while the identification and assessment of fractures show the potential to aid operators during the development of their hydraulic fracturing program. Borehole caliper and shape assessment in real time can be used to modify the drilling parameters and to adjust mud weight, while providing an input into geomechanics assessment.

The LWD logs presented illustrate the factors that influence data quality and the methodology used to ensure high-resolution images are available in both vertical and high-angle wellbores using OBM. A direct comparison between data acquired while drilling and while re-logging sections is shown, highlighting the repeatability of the measurement while also illustrating the impact of time-since-drilled on the borehole. A comparison with wireline measurements highlights the potential for using the high-resolution LWD images as an alternative to wireline, where cost and risk of deploying the wireline may be high.

The ability to collect high-resolution images in OBM in wellbores ranging from 5¾ to 6¾ in. ensures that increased reservoir characterization is possible, leading to significant improvements in determining the viability of unconventional and other challenging reservoirs. The high-resolution amplitude images are comparable with those available on wireline technologies, and the real-time application of borehole size and shape for input into wellbore stability and geomechanics analysis ensures that common drilling hazards can be avoided.
High-Fidelity Transient Hydraulics Model for Well Construction
Authors: Amur Varadarajan Prasanna , Roguin Ghislain , Abolins Nick , Ringer Maurice
Published: September 2019

A mathematical model is developed to capture the dynamic features in the wellbore during drilling operations so that it could be used for real-time computations. The model comprises one-dimensional (1D) mud flow solvers, one for the drillpipe and the other for the wellbore annulus including the volume below the drill bit, integrated point models for the bell nipple, bottomhole assembly (BHA) nozzles, 1D shallow water model for the flowline, and point model for the bypass replicating the hydraulic circuit in the drilling rig. The model assumes compressibility of mud for the wellbore section along with its transient gel characteristics. The equations are solved using appropriate explicit numerical solvers and the results capturing the fast transients of the standpipe pressure, bottomhole equivalent circulating density (ECD), and the flow rates during dynamic drilling operations are presented to illustrate the performance of the model with field data.
A Novel Approach for System Instability Prediction Using Nodal Analysis
Authors: Fan Yilin , Sarica Cem
Published: September 2019

System instability prediction is essential when designing a production system and/or providing operational adjustment to maintain a stable production. The conventional system Nodal Analysis articulates that the system is unstable to the left of the minimum of the Outflow Performance Relationship (OPR) curve where the well loads up. However, recent data shows that there are stable production points on the left of the minimum of the OPR curve, especially for low permeability shale plays. In this work, a new practical model is presented for both conventional and unconventional wells using Nodal Analysis with a novel approach.

The new approach is based on the derivative analysis of the inflow performance relationship (IPR) and OPR at a nodal point of the bottom hole. Perturbation analysis is used to facilitate the explanation of the new model. It shows that the system is stable when the absolute value of slopes or derivatives of the IPR is greater than that of OPR. To evaluate this concept, transient numerical simulations were conducted using a commercial transient simulator at various IPR conditions, including different permeabilities, for both vertical and horizontal wells. Meanwhile, the concept is also compared with available experimental and field data.

The transient simulation and the available data presented in this study demonstrate that there are stable production operating points on the left of the minimum of the OPR curve. The system stability also depends on the reservoir permeability, i.e., the flow rate corresponding to the onset of instability decreases with decreasing permeability. The new approach predicts this trend well. Overall, the new model matches well with observation from the experiments, field data, and the transient numerical simulations.
Best Practices of Exploration: Integration of Seismic and Electrical Prospecting
Authors: Vorobev Vladimir , Safarov Ildar , Mostovoy Pavel , Shakirzyanov Lenar , Fagereva Veronika
Published: September 2019

Eastern Siberia is characterized by the extremely complex geological structure. The main factors include multiple faults, trappean and salt tectonics, the complex structure of the upper part of the section (0–1200 m) and its high-velocity characteristic (5000–6000 m/s), the high degree of rock transformation by secondary processes, low formation temperatures (10–30°C), the mixed fluid composition (gas, oil and water), and low net thicknesses (5–7 m) of productive layers. The fields of the region are among the most complex ones in the world according to the BP Company's statistics. New seismic and geologic model based on complex analyses of core, well logs, well tests, seismic and electromagnetic data allowed the Gazpromneft-GEO company to drill a series of successful wells.

Gazpromneft-GEO, LLC.holds three oil and gas exploration and production licenses within the Ignyalinsky, Vakunaisky and Tympuchikansky (Chona field) subsurface blocks (Russia, Eastern Siberia, Irkutsk Region and Republic of Sakha (Yakutia)). The area of the blocks is 6,855 sq.km, 3,050 sq.km of which are covered by the 3D seismic and high-density electric prospecting (Fig. 1). 70 exploration wells were drilled. The geological oil reserves of the Chona field are about 500 Mt. Nonetheless, the level of study of the blocks is extremely irregular, despite such significant reserves. To transfer from the exploration stage to production the capital-intensive scope of exploration is required, which expands the exploration program in time and can influence the final economic profitability of the project. The optimization of drilling costs by minimization of drilling wells and the efficiency of their drilling is the key purpose of the project.

The work was carried out within the frames of scientific research and field works at the Gazpromneft-GEO, LLC. fields in Eastern Siberia. The high-density full-azimuth ground-based seismic using the UniQ technology was performed in Russia for the first time. The electric exploration with the near-field time-domain electromagnetic method was carried out along the same lines for the first time in Russia as well. This allowed to form the high-density cube of geoelectric properties. Model based on the wells (Facies model, Petrophysics model) and field geophysical data (3D seismic survey, 3D electric exploration, gravimetric survey, magnetic survey) complexation was made. The use of the approach allows to reduce the number of wells required for exploration of fields by 40%.
Fugitive Emissions Study: How to Minimize Emissions While Utilizing Sand Separators
Authors: Wasfy Rick , Spady Darcy , Hierath Kyle
Published: September 2019

The goal for all oil and gas production facilities is to have zero fugitive emissions. This is impossible but reducing the unnecessary fugitive emissions to zero is possible with planning and correct production equipment selection. Sand separators are a critical piece of early production equipment and every time the sand is removed from these vessels’ fugitive emissions are created. In order to reduce the unnecessary fugitive emissions horizontal or low angle Desanders have shown better performance over vertical or spherical sand separators as they have a larger sand holding capacity resulting in fewer blowdowns and unnecessary fugitive emissions.

For 1 m3 (264.2 gallons) of sand stopped by each Sand Separator the Vertical geometry would produce 72% of the Carbon of the spherical vessel while the horizontal Desander would produce 26% of the spherical and the low angle tilt would produce 11%.

To optimize the process further, a scale system should be paired with the horizontal or low angle Desander so that the Desander is only blown down when needed to further reduce fugitive emissions.
Anisotropic Fault Leakage into Multiple Shallower Formations Connected to an Injection Zone
Authors: Mosaheb Mojtaba , Zeidouni Mehdi
Published: September 2019

Faults can conduct fluids to shallower formations that may adversely affect groundwater resources and ultimately surface environment during geological storage of carbon dioxide. In this study, an analytical model is derived for a multilayer system that is intersected by a leaky fault. The fault-zone structure and anisotropic flow inside the fault zone are considered which are necessary for fault leakage characterization. The fault-zone structure includes damaged zones with high permeability and a core zone in between with low permeability. The diffusivity equations are written for the multilayer system as well as the fault zone and the system of equations is solved by Laplace and Fourier transforms. The solution is capable to investigate up-, across-, and along-fault fluid flow as well as pressure variations of the shallower formations. Using the pressure variations of the injection well, the vertical extension of fault leakage to shallower formations is evaluated.
A New Mechanistic Model for Oil-Water Emulsion Rheology and Boosting Pressure Prediction in Electrical Submersible Pumps ESP
Authors: Zhu Jianjun , Zhu Haiwen , Cao Guangqiang , Banjar Hattan , Peng Jianlin , Zhao Qingqi , Zhang Hong-Quan
Published: September 2019

As the second most widely used artificial lift method in petroleum industry, ESPs help maintain or increase flow rates by converting kinetic energy to hydraulic pressure. During the entire life of an oilfield, water is invariably produced with crude oil. As the field ages, the water cut in production increases. Due to high shear force inside rotating ESPs, the oil-water emulsions may form, which can be stabilized by natural surfactants or fine solids existing in the crude oil. The formation of emulsions during oil production create high viscous mixture, resulting in costly problems and flow assurance issues, such as pressure drop increase and production rate lost. This paper, for the first time, proposes a new mechanistic model for predicting oil-water emulsion rheology and its effect on the boosting pressure in ESPs. The model is validated with experimental measurements with an acceptable accuracy.

The new mechanistic model starts from Euler equations for centrifugal pump, and introduces a conceptual best-match flowrate QBM, at which the outlet flow direction of ESP impeller matches the designed flow direction. The mismatch of velocity directions, resulted from varying liquid flow rates, is used to derive recirculation losses. Other losses due to flow direction change, friction, and leakage flow etc. are also incorporated in the new model. QBM is obtained by matching the predicted performance curve with the catalog curve for water. With the best match flow rate determined, the ESP hydraulic head under viscous fluid flow can be calculated. For oil-water emulsions, a new rheology model based on Brinkman (1952) correlation is developed, which accounts for ESP rotational speed, stage number, and interfacial properties etc. By incorporating the rheology prediction model into mechanistic model, the ESP boosting pressure under oil-water emulsion can be obtained.

The mechanistic model-predicted ESP water performance curves are found to match the catalog curves perfectly. With high-viscosity fluid flow, the model predictions of ESP boosting pressure agree well with the experimental data. For most calculation results within medium to high flow rates, the prediction error is less than 15%. With oil-water two-phase flow, the proposed rheology model predicts the effective viscosities of emulsions match testing results with 10% prediction error. The inversion points, at which the continuous phase changes from oil to water as water cut increases, are also predicted. The predictions of ESP boosting pressure under oil-water emulsion flow by coupling the mechanistic model and emulsion rheology model are comparable with experimental results.
Standardization: Successful Implementation of Driving Consistency in Deepwater Operations
Authors: Durey Daniel A , Murphy Darren J , Rueda Beatriz E
Published: September 2019

Deepwater wells are the most complex and challenging operations for today's petroleum workforce. These challenges push the limits of technology requiring high level personnel competencies and stringent safety requirements. Robust and consistent procedures aid in implementing reliable operational execution. When complex operations include multiple drill ships and TLPs, and when these activities are mirrored by separate support teams of engineers and operations there are opportunities for varying procedures, content, format, and technology applications. This misalignment evolves over time, based on individual preferences, lessons learned, and varying procedures from different service providers.

This paper discusses the efforts and outcomes of bringing standardization to Deepwater operations in the Gulf of Mexico (GOM) and to Shell's broader global Deepwater organization (DWO). Standardization efforts include full End-to-End well delivery from engineering design documents, recommended/best practices, operational procedures, workflow processes, after-action-reviews, knowledge sharing, and refreshing standards as required.

Ensuring a learning loop process is in place and actively used is a key element in keeping standard documents evergreen and has the overarching goal of preventing repeat failures and NPT events. An additional benefit is the ability to deliver documents with structured content, aligned format and standard language to both the operations teams and service providers.

The formation of a core team and central department has driven global standards, active sharing of learnings across all Deepwater business units, opened communication lines with areas previously siloed due to location, reduced cycle time for the engineering teams in re-creating procedures and demonstrated sustainable reductions in operational costs.
Monitoring Dynamic Reservoir Pressure Responses Through Cement
Authors: Garcia Elias , Stutes Gerald , Nåden Christoffer , Borgersen Kjetil
Published: September 2019

During the last five years, the use of permanent downhole gauges has proliferated in the industry. The availability of true bottomhole pressure (BHP) is imperative in validating/improving reservoir models. Similarly to the extrapolation of BHP from surface readings, the use of BHP to extrapolate formation pressure may lead to significant errors in reservoir models that do not provide operators with the competitive edge needed in the current market. Consequently, there is a drive to monitor formation pressure in-situ by placing pressure and temperature gauges in direct contact with the formation.

In recent years, operators have been drilling larger holes, deploying gauge systems on the exterior of the casing, and cementing the gauge systems in place for multiple purposes. In artificial lift applications, cemented gauge systems have helped operators to avoid costs of decompleting and redeploying gauge systems on tubing whenever the electric submersible pumps (ESP) must be serviced, or perhaps whenever operators want to convert an observation well to a producing well.

In unconventional plays, technologies involving quartz pressure and temperature gauges, oriented perforating, and well conditioning practices can enable operators to deploy multiple real-time downhole pressure and temperature gauges on casing across long horizontal sections of a wellbore. This, in turn, can provide valuable production data with which to understand cluster production performance, cross-well communication, fracture azimuth, well spacing, and stage-length production implications.

Cemented gauges enable operators to understand pressure dynamics in the overburden, cap rock, or reservoir sections. The permanently installed, casing-deployed gauges connect to the surface through cable or through deployment of wireless inductive coupling technology.
Unleashing the Power of Smart Particles for Completion Diagnostics: Advancing the Production Flow Profiling Technology with Sub-Atomic Fingerprints and Big Data Analytics
Authors: Shokanov Talgat , Khudorozhkov Pavel , Shokanov Adilkhan K.
Published: September 2019

Current multistage hydraulic fracturing operations in shale are costly, environmentally challenging and inefficient. Multistage hydraulic fracturing operations already represent close to 60% of the total drilling and completion cost for each shale well. The industry studies reported that based on data evaluated in multiple shale basins in North America alone that up to 50% of the clusters and stages do not produce in geometric completion design. Shale E&P operators need more accurate, cost-efficient, timely and actionable data on the performance of individual fracturing stages and intra-well communication to enable improved decision-making and optimization of multistage hydraulic fracturing and completion strategy, as well as overall field development.

This paper will describe a revolutionary smart tracer portfolio testing and design for multistage hydraulic fracturing stimulation. The technology enables the next generation of smart tracers coupled with advanced sub-atomic measurements that significantly reduce the completion cost and double the efficiency of the hydraulic fracturing treatments. An automated process with stringent quality control assured precise tracer addition onsite and provided accurate and actionable completion diagnostics results at fraction of the cost for high-cost measurements (e.g., PLT, DTS & DAS).

The integration of smart tracer portfolio with intelligent-completion diagnostics for E&P customer enabled by performance-flow-profile data. This data used to optimize completion strategies, achieve optimal production per foot, and reduce completion cost. Follow-up big-data analytics and 3D fracture-modeling delivered accurate, calibrated, actionable, and cost-effective completion-diagnostics results. Since tracer data are captured over several months, E&P operators are captured access to continuous flow profiling data to optimize well performance routinely when new completion-diagnostics results are received. This will enable E&P operators to significantly reduce operating cost and optimize production in shale wells.
Machine Learning for Well Log Normalization
Authors: Akkurt Ridvan , Miller Mike , Hodenfield Brooke , Pirie Iain , Farnan David , Koley Manas
Published: September 2019

A well log measurement can be modelled as the sum of three components: the formation signal, random noise, and systematic error. The sources for systematic error include tool malfunctions, shop and field miscalibrations, operator error, and inherent hardware design limitations. Log calibration, more commonly referred to as log normalization, is the process of applying corrective shifts to well logs to minimize the systematic error.In this paper we develop a machine learning approach to the multi-well log normalization problem which we believe is particularly applicable in unconventional field studies involving hundreds of wells of varying data quality and vintage.

We start by applying machine learning to the multi-well normalization problem, where the reference unit and reference wells are selected by the geoscientist. The reference unit is typically a laterally extensive stratigraphic interval with a consistent log response over the area of interest, which in our case is a tight limestone with small amounts of dolomite and/or silt. The reference wells are those that do not require any normalization. A predictive machine learning model is trained using log data from the reference unit in the reference wells, and a regression-based optimization algorithm is used to solve for constant shifts which are applied as normalization corrections for density and neutron logs in the remaining wells.

The process of selecting reference wells and picking the boundaries of the calibration unit can be subjective; it is influenced by the experience of the geoscientist with the area of interest, the pressures of project timelines and the availability of sufficient resources. The impact of these human-introduced biases can be severe in large projects where a team of geoscientists is engaged to process hundreds of wells: inconsistent normalization practices can lead to large errors in computed reservoir properties.

As a solution to minimize such inconsistencies, we propose to extend the use of machine learning to create a seamless workflow that is automated and requires minimal user involvement in the execution phase. Towards this objective, we incorporate an additional machine learning component, which eliminates the requirement for a-priori knowledge of the reference unit boundaries. The resulting workflow produces consistent and high-quality results that compare very well to those produced by manual Log Normalization workflows run by experts.

Comparison of machine learning based results against expert answers show that the machine learning approach offers an efficient alternative to manual log normalization where gains can be significant in projects involving large numbers of wells, as in the case of unconventional plays.
Drainage Areas, Shapes, and Reserves for Wells in Reservoirs with Multiple Fluid Contacts / Constant Pressure Boundaries
Authors: Prasun Samir , Kumar Anil
Published: September 2019

Well drainage areas and shapes for wells in reservoirs with aquifer contact or gas-oil contact (constant pressure boundary) take varying shapes, such as, water coming from one-side (edge water drive) to water coming from 3-sides when the 4th-side is a sealing fault. This information is important in well test interpretations, peripheral flooding, aquifer injection, gas and CO2 aquifer storage, geothermal reservoirs, and any subsurface recovery schemes involving injection-production well pairs. A knowledge of well drainage shapes is helpful in optimizing well placement, well productivity estimations, and to maximize reserves.

Results show that for a 2-well 3-sided water-drive reservoir system, each well drains an equal area when the well-rates are equal; however, the drainage areas of a well increases logarithmically with an increasing ratio of its flow rate to that of an adjacent well. In case of a multiple well system, results show that the drainage area of well closer to water contact is smaller than that of an interior well, farther away from the water-contact. Results are presented in graphical form and equations to determine the drainage area and shapes for varying production rate-ratios between wells in a multiple constant pressure boundary rectangular reservoir. An algebraic procedure is presented to generalize results from a 2-well system for extension to a multi-well system with similar multiple constant pressure boundary conditions. The equations yield result within 5% of those obtained from complex streamline simulations. A well's location within its drainage area is needed to determine mean well pressures from MBH (Matthews-Brons-Hazebroek) functions for water drive reservoirs, and to estimate productivity index and cumulative water influx volumes.
Fast-Track Qualitative Interpretation of Seismic Data in a Permanent Reservoir Monitoring PRM Setting for a Brazilian Field
Authors: Maleki Masoud , Danaei Shahram , Davolio Alessandra , José Schiozer Denis
Published: September 2019

Permanent Reservoir Monitoring (PRM) in systems deep-water settings provide on-demand snapshots for hydrocarbon reservoirs at different times during their production history. Delays in the interpretation turn-around of 4D seismic data reduce some benefits of the PRM. These delays could adversely impact the decision making processes despite obtaining information on demand. Using fast-track approaches in 4D seismic interpretation can provide timely information for reservoir management. This work focuses on a fast-track 4D seismic qualitative interpretation in PRM environment, with the aim of choosing the best seismic amplitude attribute (4D) to use. Different seismic attributes are extracted and the one with high signal-to-noise ratio is selected to carry out the 4D qualitative interpretation. All 4D signals are juxtaposed with well production history data to increase confidence in our interpretation. The selected attribute can be interpreted and used for the foreseeable life of field. This workflow has been developed and applied on post-salt Brazilian offshore field to choose the best seismic attribute to conduct the 4D seismic qualitative interpretation.
Challenges and Opportunities for Commercial-Scale Carbon Capture and Storage in Kansas
Authors: Holubnyak Yevhen , Dubois Martin , Hollenbach Jennifer , Hasiuk Franciszek
Published: September 2019

Results of the Integrated CCS for Kansas pre-feasibility study indicate that large-scale CO2 capture, transportation and storage in saline aquifers in Kansas is both technically and economically feasible and deserving of further study. Based on the technical work on multiple geologic sites, there appear to be up to four sites within the North Hugoton Storage Complex (NHSC) in Southwest Kansas where >50 million tons CO2 could be injected over a 25- to 30-year period and safely stored in a set of stacked saline aquifers at ideal depths of 5200-6400 ft. The saline aquifers (Mississippian Osage, Ordovician Viola, and Cambrian-Ordovician) are overlain by oil reservoirs that are candidates for CO2 Enhanced Oil recovery (EOR). Of the four possible sites in the NHSC, the Patterson site was chosen as the primary site for a CarbonSAFE Phase II project. Patterson was chosen because the operator of the overlying fields, Berexco, was a long-term research partner of the Kansas Geological Survey (KGS), having participated in several DOE-funded studies with the KGS. Patterson has EOR opportunities in overlying reservoirs and most of the prospective injection site is already unitized.

Capture, compression and transportation of large volumes of CO2 is economic in the region, particularly since the extension and expansion of Federal 45Q tax credits in February 2018 that provide $35/ton for CO2 stored during EOR and $50/ton if stored in a saline reservoir and can be captured for a 12-year period. Without these credits, saline aquifer storage is not economically viable. The most economic scenario involves CO2 aggregated from multiple ethanol plants via small-diameter pipelines that tie into a main trunk line for delivery to market. CO2 EOR likely needs to be part of the system to provide economy of scale and, potentially, additional subsidy for saline aquifer injection through CO2 sales. High capture costs at the two power plants and refinery in this study make them non-economic options without further subsidy that may arise from a large regional pipeline system.

Legal, regulatory, public policy aspects of a project of the scale envisioned will require significant changes at the State level. In particular, legislation that would regulate capture, transportation, injection and storage as a public utility would be required along with allowances for eminent domain to be used for pipeline right-of-way and pooling of pore space. Streamlining the U.S. EPA UIC Class VI well permit process and/or establishing State primacy would further support development of commercial-scale CCS. Effective public outreach is critical for support of State regulatory changes, and for public acceptance, particularly in light of possibility for induced seismicity due to injection in certain areas and mixed public opinions about pipeline construction.
Identifying Depleted Induced Fractures from Offset Wells Using Common Drilling Data
Authors: Wutherich Kevin , Srinivasan Sridhar , Downie Robert , Katon Bill
Published: September 2019

This paper presents a new methodology that takes readily available drilling data, to identify the location and relative magnitude of localized depletion that is likely caused by induced fractures that are intersected by a newly drilled well. This paper describes the process used to identify the fractures and presents a case study in the Utica Shale that validates the results.

In recent years, mechanical specific energy (MSE) has been used to assess mechanical properties of rocks. It is further known that changes in reservoir pressure will also influence MSE. This new process analyzes a modified mechanical specific energy, and looks for anomalous increases in MSE, which should be present when drilling through a depleted fracture. To verify the existence of depleted fractures, a set of three wells were analyzed using this technique, a parent well, and two child wells.

Analysis showed that there were no signs of depleted fractures detected in the parent well, while the two child wells both contained multiple drilling signatures that were consistent with depleted fractures. The location of the apparent depleted fractures in the child well were not only consistent with the location of the parent well, but also sections in the parent well that were most likely to create dominant fractures.

The identified fractures in the child wells, also were consistent in location, magnitude and area of effect across both wells. These consistencies further promote the conclusion that dominant fractures created while completing the parent well, being penetrated and identified in both child wells.

Based on the work done, there is clear indication that the proposed methodology can potentially be used to identify depleted fractures. This information can further be used in order to design completion strategies aimed at reducing both the probability and severity of parent-child fracture interactions such as frac hits.

The paper presented will describe the first successful attempt to characterize depleted induced fractures using standard drilling data, without the use of any additional tools being run in the wellbore. This process will provide significant impact, not only in designing completions for parent-child well pairs, but will also further the understanding of far field fracture effects such as the extent of fracture extension, depletion around a fracture, and implications for well spacing.
Waterflooding Optimization under Geological Uncertainties by Using Deep Reinforcement Learning Algorithms
Authors: Ma Hongze , Yu Gaoming , She Yuehui , Gu Yongan
Published: September 2019

Recently, substantial technical progress has been made to solve complex tasks in the field of artificial intelligence (AI) by incorporating deep neural networks into reinforcement learning (RL). In this paper, four state-of-the-art deep RL algorithms are applied to optimize the net present value (NPV) of waterflooding (WF) under geological uncertainties by adjusting the water injection rate. They include the deep Q-network (DQN), double DQN (DDQN), dueling DDQN, and deep deterministic policy gradient (DDPG). A set of fifty reservoir realizations are generated by using a geostatistical technique to account for the geological uncertainties. It is found that the deep RL algorithms can optimize the WF in a 3-D 3-phase (oil-water-gas) reservoir under geological uncertainties. More specifically, both DQN and particle swarm optimization (PSO) converge to the same highest NPV, whereas the other three deep RL algorithms can find some local optimum NPVs due to the exploration-exploitation problem. DDPG converges faster than PSO and requires the least numerical simulation runs among all deep RL algorithms. The optimum water injection rate determined in the consideration of geological uncertainties not only increases the expected NPV but also reduces its standard deviation. The optimum WF starting time is found to be in the middle of the primary production. In this way, the solution-gas drive is continued and the water-cut is decreased. The production performances are compared under three different water injection scenarios: no-control, reactive-control, and optimum-control. The optimum-control scenario achieves a low water-cut and a stable oil production rate.
Early Warning Systems - Using PTA Analysis of DFITs to Understand Complex Hydraulic Fractures and Optimize Treatment Designs
Authors: Nicholson A. Kirby , Hawkes Robert V. , Bachman Robert C.
Published: September 2019

This paper outlines methods to characterize hydraulic fracture geometry and optimize full-scale treatments using knowledge gained from Diagnostic Fracture Injection Tests (DFITs) in settings where fracturing pressures are at or above the overburden gradient.

Hydraulic fractures, whether created during a DFIT or a larger scale treatment, are usually represented by vertical plane fracture models. These models work well in a relatively normal stress regime with homogeneous rock fabric where fracturing pressure is less than the Overburden (OB) pressure. However, many hydraulic fracture treatments are pumped above the OB pressure. This high pressure may be caused by near well friction or tortuosity but may also be the result of more complex fractures in multiple planes.

Bachman et al (2012, 2015), Hawkes et al (2018) and Nicholson et al (2019) advanced DFIT analysis by using the Pressure Transient Analysis (PTA) technique. This allows the identification of flow regimes useful for understanding fracture geometry and closure behavior beyond that available from more familiar G-function analysis techniques. In this paper DFITs from the Duvernay, Montney, Rock Creek and Cardium formations of Western Canada are analyzed using the PTA method. Particular attention is given to Early-Time Flow Regimes (ETFRs) present between the end of pump shut-down (End of Job Instantaneous Shut-In Pressure, EOJ ISIP) and the 3/2-slope Nolte flow regime. Identification of pressure gradients at the start and end of these flow regimes is of vital importance to the interpretation process. This allows the authors to build on case histories of DFIT-derived fracture geometry interpretations presented in Nicholson et al (2017, 2019).

Procedures are proposed for picking Farfield Fracture Extension Pressure (FFEP) in place of conventional IIP estimates while distinguishing between storage, friction and tortuosity vs. fracture geometry indicators. Analysis of FFEP and ETFRs combined with the context of rock fabric and stress setting are useful for designing full-scale fracturing operations. A DFIT may help identify potentially problematic multi-plane fractures, predict high fracturing pressures or screen-outs. Fluid and completion system designs, well placement and orientation may be adjusted to mitigate some of these effects using the intelligence gained from the DFIT early warning system.
An Experimental Investigation of Dynamic Behavior of Gravity-Driven Downhole Separators
Authors: Lopez Jorge , Pereyra Eduardo , Sarica Cem
Published: September 2019

An experimental study of a gravity-driven downhole separator for a pumped horizontal or deviated well is presented in this study. It considers the effects of the upstream flow, gas and liquid flow rates and deviation angles on the global separation efficiency and the free gas at the pump intake.

The efficacy of downhole separators is typically tested under steady-state conditions where the fluids are injected above the separator. A new outdoor facility, which allows the injection of a two-phase mixture below the separator was designed, constructed, and used in this study. Gas and liquid flow rates and deviation angle are varied to study the liquid holdup in the liquid-rich outlet and the separator efficiency.

The experimental results demonstrate the effects of the operation conditions and deviation angle on the behavior of downhole separators. It is found that the separator has two regions of performance; namely, high efficiency region and a region where the efficiency decreases with the liquid flow rate. Moreover, the effect of the deviation angle affects the results. The findings provide conditions under which and where the separator can be operated efficiently in the field.