bluuebunny/crossref_metadata_2025 huggingface dataset:
Automatic Drilling Dynamics Interpretation Using Deep Learning
Authors: Chen Wei , Yu Yingwei , Shen Yuelin , Zhang Zhengxin , Vesselinov Velizar
Published: September 2019

Severe drilling dynamics of a bottomhole assembly (BHA) causes energy to dissipate into vibrations which undermines drilling efficiency. Dangerous dynamics modes, such as backward whirling and high frequency torsional oscillation, could cause downhole drilling tools to fail prematurely. To mitigate the risk of failure due to these dangerous conditions, it is critical to identify the damaging dynamics modes by interpreting the drilling data. Based on a deep learning approach, a novel method was proposed to automatically identify severe drilling dynamics modes directly from the time-series data.

The drilling dynamics data can be obtained from either a downhole sensor measurement or transient dynamics simulation. First, a deep neural network, which is composed of convolutional and fully connected layers, is employed to explore patterns in the data by generating a feature map of drilling dynamics. Knowledge of drilling dynamics physics can be used to facilitate data clustering in the feature map. Each data cluster can be tagged with the corresponding drilling dynamics mode. Using the tagged dataset, a machine learning classification model can be trained to automatically identify the dynamics modes based on the input of time-series drilling data.

The deep learning approach can be implemented to recognize a collection of dynamics modes of BHA, such as various whirling patterns and high frequency torsional resonance. The most commonly available drilling dynamics data channels, accelerations and collar RPM, were used as the model inputs. The deep neural network was trained to predict the next data sample based on the previous time-series data. One of the hidden layers of the neural network was employed to generate the feature map, in which the dataset forms several clusters. The orbits of BHA movement were plotted on top of the clusters for pattern visualization. After this practice, the simple polygon boundary was drawn between whirling and stable cases, and the dataset was tagged automatically. With the tagged dataset, the classification model was trained to identify various whirling patterns and the stable drilling state. Similar processes can be readily applied to interpret other dynamics modes. Interpreting the drilling dynamics modes provided a high-level description of the data, which offered clues on how to optimize BHA design and drilling practices to improve efficiency.

The automatic interpretation of drilling dynamics data can significantly improve the consistency and efficiency of the existing manual interpretation workflow. The generated feature map enables the exploration of new motion patterns and new vibration modes. This approach eliminates the need to manually tag the data. With minimum human interactions, the dataset can be automatically tagged. The model employs only the raw time series data of basic dynamics channels as inputs, which makes the algorithm universally applicable for various data sources.
Novel Slow-Release Particle Technology for Use in Hydraulic Fracturing Applications
Authors: Yang Chao , Navarrete Reinaldo , Asadi Mahmoud , Karber Lionel , Hagelin Kyle
Published: September 2019

The formation and deposition of solids including mineral scale, paraffin, and asphaltene, may occur at any location of the oil and gas production system, from the bottom of the well to a gathering facility, due to the changes in the physical and chemical conditions associated with production fluids. Depositions can reduce the formation permeability, reservoir transmissibility and have detrimental impact on production rates during oil and gas production. Common practice is to complete the well and then apply a treatment and remediation program as necessary, including squeeze treatments and batch treatments.1

Horizontal, multi-stage hydraulic fracturing is widely used in the industry as stimulation practice.2 A single application providing long-term treatment is financially and operationally beneficial for operators. A solid inhibitor with slow-release active additives can extend the treatment life and reduce subsequent intervention costs attributed to deposition prevention and/or removal.

This paper reports on a new, slow-release particle technology developed for applications in hydraulic fracturing. This new technology does not rely on adsorption, impregnation or any other technology of embedment of additives onto a substrate. The new slow-release particles exhibit improved delayed release profile, high strength, and the capacity to incorporate active components, such as scale or paraffin inhibitor, either singly or in combination.
Surpassing the Challenges of a Robotic Traction System for Movement inside Long Flexible Obstructed Pipes
Authors: Donadel Basso Eduardo , André Perondi Eduardo , Francisco Lisboa Santos Hugo , Augusto Couto Barone Dante , Luis da Silva Júnior Anselmo , Viegas Wentz André , Mendel Henrique
Published: September 2019

The obstruction inside flexible lines with hydrates or paraffins is quite common in offshore production systems. In these cases, in order to perform the clearance of the pipes, many different techniques, usually time consuming and expensive, are currently used. This article presents the development of a new self-propelled robot that is under design to become an alternative solution for this problem, which has been a research challenge by decades.

The use of robots with umbilical cables inside long obstructed pipes with several curves and bends is currently an important challenge in the robotic field, especially due to the increased traction forces that may occur. The main challenge is the force in the umbilical cable caused by the friction between the cable and the inner pipe surface. This force can be theoretically outlined by the capstan Euler-Etelwein equation (usually applied to the case of rounding a capstan with a rope). In an early study, a theoretical model for cable traction was developed and experimentally validated. This model was used to calculate a typical friction force in a standard pipeline. Several in-pipe movement strategies were analyzed and a suitable mechanism was defined as the main element for the robot traction mechanism. Therefore, we show in this study that the traction challenge can be surpassed by a properly cable materials selection composed with a suitable traction system design. A mechanism base in an inchworm-like movement was selected due to its high traction capacity and, based in an extensive study, a hybrid (electric-hydraulic) system was developed. The electric power transmission is provided through the umbilical, and electric motors drive pumps which supply hydraulic power to linear pistons that execute the movement of the mechanical elements, moving the entire system. Previous analysis and tests indicate that the designed system will be suitable to perform the necessary missions.
Integrated Characterization of the Fracture Network in Fractured Shale Gas Reservoirs—Stochastic Fracture Modeling, Simulation and Assisted History Matching
Authors: Wu Yonghui , Cheng Linsong , Killough John E. , Huang Shijun , Fang Sidong , Jia Pin , Cao Renyi , Xue Yongchao
Published: September 2019

The large uncertainty in fracture characterization for shale gas reservoirs seriously affects the confidence in making forecasts, fracturing design, and taking recovery enhancement measures. This paper presents a workflow to characterize the complex fracture networks (CFNs) and reduce the uncertainty by integrating stochastic CFNs modeling constrained by core and microseismic data, reservoir simulation using a novel edge-based Green element method (eGEM), and assisted history matching based on Ensemble Kalman Filter (EnKF).

In this paper, the geometry of CFNs is generated stochastically constrained by the measurements of hydraulic fracturing treatment, core, and microseismic data. A stochastic parameterization model is used to generate an ensemble of initial realizations of the stress-dependent fracture conductivities of CFNs. To make the eGEM practicable for reservoir simulation, a steady-state fundamental solution is applied to the integral equation, and the technique of local grid refinement (LGR) is applied to refine the domain grids near the fractures. Finally, assisted-history-matching based on EnKF is implemented to calibrate the DFN models and further quantify the uncertainties in the fracture characterization.

The proposed technique is tested using a multi-stage fractured horizontal well from a shale gas field. After analyzing the history matching results, the proposed integrated workflow is shown to be efficient in characterizing fracture networks and reducing the uncertainties. The advantages are exhibited in several aspects. First, the eGEM-based Discrete-Fracture Model (DFM) is shown to be quite efficient in assisted history matching of large field applications because of eGEM’s high precision with coarse grids. This enables simulations of CFNs without upscaling the fractures using continuum approaches. In addition, CFNs geometry can be generated with the constraints of core and microseismic data, and a primary conductivity of CFNs can be generated using the hydraulic fracturing treatment data. Moreover, the uncertainties for CFNs characterization and EUR predictions can be further reduced with the application of EnKF in assimilating the production data.

This paper provides an efficient integrated workflow to characterize the fracture networks in fractured unconventional reservoirs. This workflow, which incorporated several efficient techniques including fracture network modeling, simulation and calibration, can be readily used in field applications. In addition, various data sources could be assimilated in this workflow to reduce the uncertainty in fracture characterization, including hydraulic fracturing treatment, core, microseismic and production data.
Transient Performance Behaviors of a Well Intercepting a Uniform-Flux Hydraulic Fracture within a Shale Reservoir — A Fractional Integration Approach
Authors: Valdes-Perez Alex R , Blasingame Thomas A , Larsen Leif
Published: September 2019

The standard modeling techniques for fractured wells were developed for conventional (higher permeability) reservoirs. The application of these techniques in fractal (shale) reservoirs often yield physically-inconsistent results which can cause over/mis-interpretation of the transient data. The purpose of this work is to provide a new modeling scheme using the "fractional integration" solution for hydraulically fractured wells producing from a fractal reservoir. This methodology takes into account the reservoir heterogeneity in the modeling of the fluid flow towards the hydraulic fracture and provides physically consistent diagnostic interpretations and parameters.

We have used the "fractional integration" approach to "couple" the fluid flow from a fractal (reservoir) to a Euclidean object (i.e., the hydraulic fracture). This approach requires rescaling the coordinate axes for the fractal reservoir using power-law relations.

In this work we derive generalized models that can reproduce the classic Euclidean hydraulic fracture scenarios. We studied the constant-rate and constant-pressure cases and found that our proposed models yield the following three flow periods: Period 1: Early Fractal-Formation (EFF) flow. This flow period is analogous to the formation-linear flow for conventional reservoirs. The transient signature of this flow period is only influenced by the conductivity index (reservoir heterogeneity fractal parameter).Period 2: Late Fractal-Formation (LFF) flow. This flow period can also be observed in conventional reservoirs, although its characteristics are not extensively documented in the existing literature. This period is influenced by the fracture length and the reservoir fractal parameters, i.e., the fractal dimension and the conductivity index.Period 3: Pseudo-Fractal (PF) Flow. This is analogous to the pseudo-radial flow regime for conventional reservoirs. The transient performance behavior of this flow period depends on the two reservoir fractal parameters defined in this work.

In performing this work, we provide the following technical contributions: We introduce a physically-consistent modeling scheme for a well with uniform-flux vertical fracture producing from a fractal (shale) reservoir.We show that the transient flow behavior for a well intercepting a uniform-flux vertical fracture can exhibit three distinct flow periods.We provide field demonstration cases which are analyzed and interpreted using the new solutions presented in this work.
Method for Characterizing the Aggregation of Wax Crystals and Improving the Wax Deposition Model
Authors: Wang Zhihua , Zhu Chaoliang , Lou Yuhua , Cheng Qinglin , Liu Yang , Wang Xinyu
Published: September 2019

Wax crystals can aggregate and precipitate when the oil temperature decreases to below the wax appearance temperature (WAT) of waxy crude oil, which has undesirable effects on the transportation of crude oil in pipelines. Thermodynamic models considering the molecular diffusion, shearing dispersion, and shear stripping as well as hydrodynamic models have been developed for predicting the wax deposition in crude oil pipelines. However, the aggregation behavior of wax crystals during crude oil production and transportation is not well understood. The microscopic rheological parameters have not been related to the bulk flow parameters in the shearing field, and the prediction of the wax deposition behavior under complex conditions is restricted by the vector characteristics of the shearing stress and flow rate. A set of microscopic experiments was performed in this study to obtain the basic information from images of wax crystals in shearing fields. A novel method of fractal dimensional analysis was introduced to elucidate the aggregation behavior of wax crystals in different shear flow fields. The fractal methodology for characterizing wax crystal aggregation was then developed, and a blanket algorithm was introduced to compute the fractal dimension of the aggregated wax crystals. The flow characteristics of waxy crude oil in a pipeline were correlated with the shearing stress work, and a wax deposition model focusing on shearing energy analysis was established. The results indicate that a quantitative interpretation of the wax crystal aggregation behavior can be realized using the fractal methodology. The aggregation behavior of the wax crystals is closely related to the temperature and shearing experienced by the waxy crude oil. The aggregation behavior will be intensified with decreasing temperature and shearing effect, and a wider fractal dimension distribution appears at lower temperatures when the same shear rate range is employed. The lower the fractal dimensions obtained at high temperature and strong shear action, the weaker will be the nonlinear characteristics of the wax crystal aggregation structure, and thus, the potential wax deposition will be inhibited during waxy crude oil production and transportation. Furthermore, the improved model provides a method for discussing the effects of the operating conditions on wax deposition. The average relative deviation between the improved model prediction results and experimental results from the literature is 3.01%–5.32%. The fractal methodology developed in this study and the improvement in wax deposition modeling are beneficial for understanding and optimizing flow assurance operations in the pipeline transportation of waxy crude oils, and the results are expected to facilitate a better understanding of the wax crystallization and deposition mechanism.
Elimination of the Sustained Casing Pressure using Self-Healing Cement in Turkmenistan Section of the Caspian Sea
Authors: Nafikova Svetlana , Bugrayev Amanmmamet , Taoutaou Salim , Baygeldiyev Gaygysyz , Akhmetzianov Ilshat , Gurbanov Guvanch , Eliwa Ihab
Published: September 2019

A major operator on the Caspian Turkmen shelf has started to encounter sustained casing pressures (SCP) attributable to insufficient isolation across a hydrocarbon gas zone, due to downhole stresses and other contributing factors. Enhanced placement techniques of conventional cements failed to prevent SCP, confirming the requirement for an alternative cement system that can withstand anticipated stresses and resolve this challenge. An innovative and cost-effective solution was applied and successfully solved the SCP challenge due to its unique self-healing properties.

If cracks or microannuli occur and hydrocarbons reach the cement, the system has the capability to repair itself, restoring integrity of the cement sheath without external intervention. The cement system is placed conventionally in the annulus across or above the hydrocarbon-bearing formation. It then acts as a pressure seal, expanding to accommodate downhole changes and healing if any hydrocarbon reaches it. This technology has been used in four wells in the field with excellent results.

Two wells were used to demonstrate the capabilities of the self-healing cement as a lead cement slurry, which created a cap over the pay zones. The self-healing cement was designed with low Young's modulus for optimum flexibility. To minimize the risk of set cement integrity failure due to microannuli or microdebonding from chemical shrinkage after setting, linear expansion up to 1.2% was incorporated into the design. After cementing, the wells were intentionally exposed to a sequence of high-pressure tests, which induced annular pressures in the wells. However, because of the self-repair capability of this cement, isolation and integrity were effectively restored in the two wells within 1 to 2 weeks without external intervention. As a result, the self-healing cement technology has become the standard for the field for all future wells, and the operator plans to extend the self-healing cement technology to other fields with similar challenges.

This paper clearly demonstrates successful casing pressure remediation without intervention by engineering a flexible, self-healing cement system. The design strategy, execution, evaluation, and results for two wells are discussed in detail and will help to guide future engineering and operations around the world.
Poroelastic Analytical Solution for the Nonlinear Productivity Index of Wells in Stress-Sensitive Reservoir Rocks
Authors: Zhang Wei , Mehrabian Amin
Published: September 2019

Reservoir depletion can induce substantial changes in the stress state of the rock. The coupled interaction between the pore fluid pressure and rock stress will then alter the reservoir permeability, which in turn reversely affects the productivity index of the production well. A new nonlinear analytical solution is developed for the drawdown-dependent productivity index of reservoirs under steady-state flow. Biot's theory of poroelasticity is used to derive the depletion-induced changes in the reservoir rock porosity and permeability. The well-known Mindlin's solution for a Nucleus of Strain in a semi-infinite elastic medium is applied as Green's function and integrated over the depleted volume of reservoir rock to obtain the 3D distribution of stress and volumetric strain distributions. The fluid transport equation is nonlinearly coupled to the solid mechanics solution via the stress-dependent permeability coefficients. A perturbation technique is applied to mathematically treat the described nonlinearity to solve for the coupled equations of pore fluid flow and rock stress under steady-state flow. The good match between the obtained analytical approximations for productivity index and the numerical solutions verifies the correctness and robustness of the proposed model.

Results indicate and confirm the expected strong dependency of the well productivity index to the drawdown magnitude as well as the poroelastic constitutive parameters of the reservoir rock, with the highest sensitivity to drained bulk modulus, followed by the reservoir depth and solid-grain modulus. The lowest PI sensitivity is to the pore fluid modulus and Poisson's ratio. The resulting productivity index is found out to be drawdown-dependent, which can render values substantially different than the productivity index estimate from the conventional flow-only analysis. The presented estimates for the related nonlinear productivity index can be readily used by the practicing engineers.
Application of Downhole Well Integrity Technology in the Petroleum Industry, A Case Study in the Horizontal Wellbore
Authors: Tao Li , Qiang Chen , Qiang Sun , Weiye Han , Shouzhi Huang , Longda Liu
Published: September 2019

Wellbore integrity was a thorny issue in China since hundreds of thousands of wells needed to be repaired annually, leading to cost increase and production delay. This problem became more excruciating in the long horizontal wellbore considering the high risk of downhole tools stuck. So far casing damage in the horizontal wellbore was either chemically plugged or separated by bridge plug, posing huge threat to the reservoir and future operations. Solid expandable tubular was a rising star in the downhole workover programme, its application in the horizontal wellbore would further enrich our technical warehouse to enhance the wellbore integrity.

In this paper, the challenges of horizontal wellbore workover operations were presented; the expandable technology was introduced and then innovated the adapt to the challenges, finally its field operation was described and relevant summaries of lessons were demonstrated.

The results indicated that as the number of horizontal well increased dramatically, problems such as casing damage, sand plugging occurred more frequently, downhole tools usually needed additional force to forward in the horizontal part to finish well logging or other activities, casing integrity was necessary to prevent the stuck of downhole tools.

Solid expandable tubular was a field proven technology, in order to overcome issues like tripping in process, expansion hurdles in the irregular well trajectory, the structure of solid expandable tubular was optimized radically. First the material of tubular was changed to achieve N80 steel grade after expansion, the OD of tubular was adjusted to maximize the annulus space between the casing and the tubular. Second the thread was restructured the further enhance its strength. Finally the rubber outside the tubular was innovated to prevent being worn out as much as possible during its friction with the horizontal wellbore. Field operation was carried out in west China, 18m length of expandable tubular was deliver into the end of 327m horizontal wellbore, expansion process was started and 41MPa expansion force was recorded.

This paper served to enrich our capabilities to deal with workover operation in the horizontal wellbore, its content helped better understand the principle, procedure and potential of this enable technology.
A New Cased-Hole Porosity Measurement for a Four-Detector Pulsed-Neutron Logging Tool
Authors: Schmid Gregory , Pemper Richard , Dolliver Darrell , Mekic Natasa , Musselman Jon
Published: September 2019

A new cased-hole porosity measurement has been developed for a four-detector pulsed-neutron logging tool. The measurement is based on a capture count rate ratio from two different detectors. To determine an accurate porosity, the ratio is characterized in the laboratory in order to establish a ratio-to-porosity transform. To account for varying measurement conditions in the field, environmental corrections, based on laboratory studies and computer simulation, are applied. As an alternative to environmental corrections, the capture ratio can also be actively compensated for the environment by using the results of a dual-exponential fit to the capture time decay spectrum. In particular, we can compensate for the borehole fluid salinity by using the borehole component of the dual-exponential fit, and we can compensate for the effective density of the borehole environment by using an inelastic ratio derived from the capture subtracted burst yields. The final porosity measurement has been shown to provide accurate results in the field through a comparison with data from open-hole logs.
Simplified Dark Data Analytics of Everyday Completions Data, and its Relation to Observed Induced Seismicity Events: An Unconventional Big Data Solution
Authors: Qiu Yusheng , Adams Matthew , Grasselli Giovanni
Published: September 2019

Diagnostic fracture injection tests (DFIT's), or "mini-fracs" are often used to gauge many reservoir and fracture design parameters. However, DFITs are not always conducted in conjunction with the main completions work. This paper proposes a novel workflow to determine the instantaneous shut-in pressure (ISIP) from readily available completions data. This is a valuable parameter in itself as related to the least principal in-situ stress states as demonstrated by the stress change relationships near faults in Lavoie et al. (2018).

Directly using completions data from fracture stimulation operations, the authors have leveraged on the water-hammer signature in bottom-hole pressure data during completions to process the ISIP for each completions stage. Within this study, completions data from ~2100 stages from ~300 horizontal Montney formation wells were analyzed. A MATLAB script was used to automate the derived ISIP stress trends over the Montney formation and to deduce the ISIP in a consistent format.

This novel workflow also validates the expected in-situ stress trends at depth, with a relationship of high ISIP gradients closer to fault zones similar to stress change behaviour as shown in Lavoie et al. (2018). Specifically, a positive spatial relationship was observed pertaining to local ISIP gradients, the lithostatic gradient, the minimum in-situ stress, and the propagation of hydraulic fractures that are prone to reactivation of critically stressed faults. Based on our real-time observations, field operators may allow to flowback a well for a short amount of time to deplete the anthropogenic reservoir pressure and stress shadowing prior to resuming fracture stimulation.

Considering the continued push for higher fluid and sand loading in industry in the development of unconventional assets as an economic driver, there also exists a large and tangible corporate citizenship opportunity of mining real time completions dark data with the possibility of relating that live feed as a prescriptive tool to mitigate reactivation of critically stressed faults. This case study focuses on the Montney formation as a basis for processing easily available data from standard operations in an effort of systematically designating areas prone to seismicity risk in future hydraulic fracturing operations based on automated real-time analytics of dark data.
Application of Assisted History Matching to Unconventional Assets
Authors: Al-Rukabi Muhammed , Forouzanfar Fahim
Published: September 2019

Characterization of key parameters in unconventional assets continues to be challenging due to the geologic heterogeneity of such resources and the uncertainty associated with fracture geometry in stimulated rock. Limited data and the accelerating pace of asset development in plays like the Permian present an increasing need for an efficient and robust assisted history matching methodology that produces better insights for asset development planning decisions, e.g. well spacing.

A multi-scenario approach is presented to build an ensemble of history matched models that take into account existing uncertainty in reservoir description and well completions. We discuss parametrization of key uncertainties in the reservoir rock, fluid properties, fracture geometry and the effective permeability of stimulated rock. Ensemble-based assisted history matching algorithms are utilized to reduce and characterize the uncertainties in the model parameters by honoring various types of data including field dynamic data and measurements. We discuss the implementation of automated schemes for weighting of various types of data in the ensemble-based history matching algorithms. These schemes are introduced to define the history matching objective functions from various types of data including bottomhole pressure data, and the oil, water and gas productions rates. The computational results show that our adaptive scheme obtains better history match solutions.

The presented multi-scenario approach, coupled with the ability to efficiently run a high number of scenarios, enables better understanding of reservoir and fracture properties and shortens the learning curve for new development in unconventional assets. The shown case study illustrates a comprehensive analysis, using thousands of simulation cases, to obtain multiple history match solutions. Given the non-uniqueness of reservoir history matched models presented in the scenarios, this workflow improves forecasting ability and enables robust business decision makings under uncertainty.
Potential of Associative Polymers as Mobility Control Agents in Low Permeability Carbonates
Authors: Ghosh Pinaki , Zepeda Angel , Bernal Gildardo , Mohanty Kishore
Published: September 2019

Waterflood in low permeability carbonate reservoirs (<50 mD) leaves behind a substantial amount of oil due to capillary trapping and poor sweep. Addition of polymer to the injected water increases the viscosity of the aqueous phase and decreases the mobility ratio, thus, improving the sweep efficiency and oil production from the tight formations. Performance of current synthetic EOR polymers is limited by salinity, temperature and injectivity issues in low permeability formations. Mechanical shear degradation can be applied to high molecular weight synthetic polymers to improve the injectivitiy; but makes the process less economical due to significant viscosity loss and consequent increase in polymer dosage. Recently, a different class of polymer has been developed called "hydrophobically modified associative polymers (AP)". The primary goal of this work is to investigate the performance of associative polymers in low permeability carbonate reservoirs. We compare the performance of associative polymers with that of conventional HPAM polymers in low permeability formations. A low molecular weight associative polymer was investigated as part of this study. A detailed study of polymer rheology and the effect of salinity at the reservoir temperature (60 °C) was performed. Additional experiments were performed in bulk and porous media to investigate the synergy of associative polymers with hydrophilic surfactant blends at different brine salinities. Single phase polymer flow experiments were performed in outcrop Edwards Yellow and Indiana limestone cores of low permeability to determine the optimum polymer concentration to achieve the desired in-situ resistance factor (or apparent viscosity). Similar experiments were performed with HPAM polymer for a comparative study. Results showed successful transport of this associative polymer in low permeability formations after a small degree of shear degradation. The resistance factors for the associative polymer were higher than those for HPAM. Shear degraded polymers showed significant improvement in polymer transport in lower permeability cores with reduction in RRF.
Casing Connection Break Detection Through Tubing in Canadian Thermal Projects. Case Study.
Authors: Ghanavati Mohsen , Volkov Maxim , Nagimov Vener , Ali Mohammadi Hamzeh
Published: September 2019

Production casings of Cyclic Steam Stimulation (CCS) or steam-assisted gravity drainage wells are exposed to significant temperature variations which in many cases resulted in casing breaks in the weakest part which are typically connection joints. The paper focuses on the new downhole logging approach, in monitoring and detecting production casing connection breaks through tubing without requirement for tubing retrieval.

The metal well barriers can be assessed by utilizing electromagnetic (EM) pulse defectoscopy. This is done by running multiple coaxial sensors downhole in tandem. Each sensor generates EM pulse and then records EM decay from surrounding metal tubes. Modeling of recorded EM decay enables precise assessment of metal loss or metal gain in up to four concentric barriers. However, the tool had never been used previously to detect minor defect features as casing breaks through the tubing. To identify casing breaks several yard and field tests have been conducted and new methodologies were developed. The last one included the recognition of specific patterns of raw EM responses, analysis of hole sensors and utilization of data from all coaxial sensors utilized during the downhole survey.

The new approach including downhole EM pulse tools and new data analysis have been implemented to detect casing connection breaks in over a hundred Cyclic Steam Stimulation (CCS) and SteamAssisted Gravity Drainage (SAGD) wells. The paper demonstrates the testing of the application feasibility in a comprehensive yard test and extends to real field examples. All detected breaks were confirmed after tubing removal and were successfully repaired. Paper highlights detection challenges due to different casing connection break types: minor breaks, partial breaks (contrary to fully circumferential), and casing breaks aligned with tubing connections. The technology has helped Operators to fulfil the objectives of connection break detection without tubing removal through a non-intrusive, safe, quick and economical approach.

Today, CSS and SAGD Operators should confirm casing integrity repeatedly prior to each subsequent steam cycle through the time and resource consuming approach of tubing removal and checking the casing integrity mechanically. Utilizing through tubing electromagnetic diagnostics, enables Operators to pick up multiple casing connection breaks in a single run without tubing retrieval.
Scaling Criteria for Hybrid Steam-Solvent Processes
Authors: Lorimer Shelley , Meza Diaz Brigida , Sawatzky Ron , Huang Xiaolan
Published: September 2019

Scaling groups for hybrid steam-solvent recovery processes are presented in this paper. A brief discussion of the derivation of the scaling groups is given first. Then an examination of the comparative behavior of these scaling groups at different scales is provided using reservoir simulation for the example of a high solvent load steam-butane gravity drainage process (i.e., steam-butane hybrid (SBH)).

Scaling groups were derived for hybrid steam-solvent recovery processes by inspectional analysis using governing equations for multi-phase flow in porous media. The effects of key mechanisms in these processes (diffusion, dispersion, advection and capillary pressure) were examined within the context of the derived scaling groups using reservoir simulation of SBH at three different geometric scales, ranging from the laboratory scale through a semi-field scale to the field scale, for one specific set of operating conditions. The scaling groups were used to analyse and interpret the numerical results.

The scaling groups were characterized according to the physical mechanisms from which they were derived. The intent of this analysis was to determine which of the mechanisms tend to be most important to the SBH process at different geometric scales. It is clear from a cursory examination of the scaling groups that all of the scaling groups representing the behavior of the SBH process cannot be satisfied when the geometric scale is changed from the laboratory scale to the field scale. The results of the study also indicate that the Pujol and Boberg scaling criteria for thermal processes seem to provide a reasonable approach for scaling SBH, when they are adapted to include the effects of dispersion. The influence of capillary pressure was secondary to other mechanisms involved in the process. It was evident from the simulations that the influence of dispersion was much more pronounced than diffusion for the solvent loading that was considered. Further, it was found that mechanical dispersity must be scaled with length to scale this mechanism appropriately in the reservoir simulator that was used in this study (CMG STARS™). As a final observation, the influence of capillary pressure was secondary to other mechanisms involved in the process.

Few studies on scaling high solvent loading hybrid steam-solvent processes have been undertaken. Using reservoir simulation to study scaling groups for these processes is a novel approach to this subject. Understanding the scalability of hybrid steam-solvent processes from the laboratory scale to the field scale would improve the capability of laboratory experiments to represent the performance of these recovery processes at the field scale.
Changing the Negative Perception of the Oil and Gas Industry In Colombia, Through an Energy Education Methodology
Authors: Guevara Israel , Pastor Paola , Saavedra Ana
Published: September 2019

In Colombia, oil and gas production contributes to a 4.4% of GDP as of 2016 and is considered a vital resource for the national economic development. Today, the oil and gas production is around 830.000 barrels per day. In the past 100 years, there are key geographical areas in the country where the oil and gas industry has been operating. Over the years, the oil and gas industry in Colombia has faced challenges with the communities behavior, environmental incidents and changes on the environment regulation. As a result of this, in the last three years Colombia has reported more than 9,000 barrels of oil per day (bpd) of deferred production, due to strikes that directly affect field operations.

The following article describes the factors considered in Colombia for the successful adaptation and application of Energy4me, a Society of Petroleum Engineers energy education methodology that explains the oil and gas concepts through innovative laboratories that help understand, in a simple way, how the oil industry works.

In the last two years, more than 8,000 people have been involved in the Energy4me program in Colombia. This paper describes the methodology applied for the successful execution of the Energy4me program; integrating the analysis of the targeted population, adaptation of the technical information and the industry's view on the environment. Additionally, it quantitatively portraits the participation of student volunteers from different universities around the country and the positive impact of this experience. Sample design techniques and data analysis are applied to quantitatively measure the results obtained, among which stands out the decrease of the energy industry rejection by at least 58%, as well as other benefits; which are backed up by the theory of shared value.

With the novel adaptation and implementation of the pedagogical methodology of Energy4Me and with the creation of new educational materials to simplify technical knowledge sharing, it is concluded that a healthy communication channel between the energy sector and the communities exposed to oil operations can be constructed to achieve a reduction in the overall communities oil and gas rejection.
SAGD Production Optimization Through Preferential Steam Allocation
Authors: Aboorvanathan Raphael , Hossini Amir , Dong Chao , Dehdari Vahid , Feeney Jay
Published: September 2019

Optimizing steam-assisted gravity drainage (SAGD) performance in oil sands reservoirs relies on the quality of steam allocation decisions made across the well inventory. With finite facility steam generation capacity, SAGD producers are typically challenged with identifying the true opportunity cost of allocating steam volumes based on well performance. This paper presents a novel technique to inform steam allocation decisions and managing SAGD reservoir pressures in service of optimizing production and consequently improving the economic performance of the asset through smarter SAGD field development planning.

The concept of marginal steam-oil-ratio (mSOR) is introduced as a method of guiding steam allocation decisions. Marginal SOR is defined as the cold-water equivalent volume of steam required to produce the next marginal barrel of bitumen from the production system in a steam constrained environment. The metric represents the opportunity cost of deploying a barrel of steam to the next best alternative in steam allocation decisions. Dynamic quantification of mSOR over the plausible range of operating pressures for each producing entity (PRDE) in the inventory (such as a well group or drainage area) is critical to optimally allocating steam when faced with reservoir challenges such as reservoir complexity and heterogeneity and transient reservoir behaviors such as thief zone interaction.

This paper prescribes methodologies to analytically and empirically quantify mSOR for a SAGD production system. Additionally, application of the concept if field production optimization is discussed under the context of integrated production modeling and constrained flow network optimization problems. A case example of applying mSOR to guide steam allocation decisions at ConocoPhillips' Surmont SAGD asset is presented under a steam constrained environment. The mSOR guided solution is validated using brute-force enumeration of steam allocation outcomes in the production system to prove production optimality. The results from this dynamic steam allocation strategy guided by mSOR characterization show significant improvements in field oil rates, field steam management efficiency and consequently the economic value of the SAGD asset.
Shifting the Perspective: Modernizing Well Density Metrics for Multi-Layer Horizontal Well Development
Authors: Hansen Mary , Hamm Brian , Wynveen Jared , Schlosser Tyler , Jenkinson David , Dang Hoang
Published: September 2019

Unconventional reservoirs with low permeability shales and siltstones are currently being developed using horizontal wells in multiple layers. As this development technique has become more common, accurately understanding well-to-well communication is increasingly critical. Well positioning, reservoir thickness and well interference effects are important factors in the success of multi-layer development. Traditional well density metrics such as wells per section and lateral well spacing do not account for the multi-layer nature of these plays. This paper introduces readily derived metrics that enable a three-dimensional (3D) quantification of multi-layer well density.

Unlike traditional analysis which considers pad development from a bird’s eye view, this paper considers the vertical cross-section of a pad which enables the 3D drainage to be quantified. The metrics Cross-Sectional Drainage Area (XDA) and Three-Dimensional Proppant Intensity (3DPI) are defined. XDA quantifies the well density relative to the thickness of the reservoir. 3DPI represents completion intensity and reservoir stimulation relative to the cubic volume of gross rock attributed to the multi-layer development. Once introduced, these two metrics are correlated to well and pad level performance. Examples from the Montney Formation in Western Canada and the Bakken Formation in North Dakota, USA are studied in detail.

Ultimate hydrocarbon recovery factors, early time well performance and production profiles are analyzed and compared to the XDA and 3DPI metrics using visual analytics and multivariate machine learning models. In both the Montney and Bakken examples, XDA correlates with well performance and 3DPI correlates with pad hydrocarbon recovery factors.
Determination of ISIP of Non-Ideal Behavior During Diagnostic Fracture Injection Tests
Authors: Ibrahim Mohamed Mohamed , Ibrahim Ahmed Farid , Ibrahim Mazher , Pieprzica Chester , Ozkan Erdal
Published: September 2019

The instantaneous shut-in pressure (ISIP) serves as an indication of the excess pressure in the hydraulic fracture due to the effect of fluid viscosity and pressure required to break the formation at the fracture tip. The ISIP value will be close to or at the fracture propagation pressure and will be greater than the fracture pressure. The ISIP is often estimated to be the pressure after the pumps are shut down, and the beginning of a pressure decline. Many approaches have been developed to estimate the ISIP from the falloff data. The development of these approaches is attributed to the persistent trials due to the difficulty of quantifying the ISIP value accurately. Giving bottomhole pressures, ISIP can be estimated by subtracting the friction pressure drop from bottomhole pressure. This approach tends to overestimate the value of ISIP as it doesn't account for friction near the wellbore or through the perforations. Another common approach to estimate ISIP is by drawing a straight line on the early falloff portion of the Diagnostic Fracture Injection Tests (DFIT).

Previous studies show that the choice of ISIP affects the net pressure calculations, but not the slope of the derivative curves and the flow regime identification. This paper presents field cases where the values of ISIP affects the interpretation of the reservoir characteristics. Thus, the determination of accurate ISIP is very crucial.

This paper reviews the previously proposed approaches for determining the ISIP and provide a state of the art simple method to determine ISIP from non-ideal falloff data. The ISIP determined from the proposed method is verified by examination of the semi-log derivative plot, and the interpreted reservoir characteristics were found to be consistent with both field and lab observations. The method was validated using field DFITs falloff data from high-pressure dependent leakoff formations as well as formations that yield normal leakoff pressure dependent.

The novelty of the proposed method is in the simplicity of determination of ISIP and the consistency with the field observations. A number of field examples from the Barnett shale are illustrated using mechanisms previously proposed in the literature as well as the method presented in this paper. The later provided consistent ISIP values after multiple iterations. Subsequently, the reservoir characteristics and calculated parameters were uniform within the same pad of wells.
Culture Eats Strategy for Breakfast: Developing Coaching Cultures in the Oil and Gas Sector
Authors: Hamp Roland , Webster David
Published: September 2019

Oil and gas businesses are often characterised as operating in volatile, uncertain, complex and ambiguous (‘VUCA’) environments, whilst also expected to meet ever more demanding operational challenges and stakeholder expectations. Within this setting the historically prevalent directive, ‘command and control’ leadership style has become increasingly ineffective at creating a workplace culture which fully enables and engages staff, especially millennials, to deliver outstanding results sustainably. This paper looks at what it takes for an organisation to shift towards a ‘coaching culture’, one in which exceptional performance is gained by a significantly higher quality of conversation between all involved in the business. The paper discusses the business context for a modern oil and gas business which necessitates a shift towards a ‘coaching culture’ for many in the sector; it sheds light on the critical elements of such a change programme and the key steps that are required for such a change to be successful; it examines the theoretical basis for development of a coaching leadership style in the sector; and it shares the authors’ practical learning from the field gained through implementation of such programmes in the sector, with examples and composite case studies.