bluuebunny/crossref_metadata_2025 huggingface dataset:
Machine Learning Approach for Irregularity Detection in Dynamic Operating Conditions
Authors: Sidahmed Mohamed , Bailey Richard
Published: September 2016

Designing systems that can detect irregularities in process monitoring data and which can be implemented efficiently is a challenge. The ability to detect and diagnose such events will help ensure stability of operations, avoiding excursions that cross thresholds reflecting safe operating limits and consequently improving process reliability and availability. Typically, using classical outlier techniques to detect anomalies assumes that a ‘normal' pattern of behavior, in a statistical sense, can be assumed and/or confirmed and used to identify what is an extreme observation. In practice, simple univariate measures of normality seldom result in effective solutions in systems whose dynamic behavior generates wide-ranging time varying data.

This paper presents a multi-criteria, data-driven approach for detecting irregularities in multivariate, time-series, dynamic systems with irregular changing patterns. The capability to automatically detect and flag such data will reduce the risk of crossing operational boundaries and improve levels of operations availability.

We developed a semi-supervised machine learning framework that provides a blue print for configuring application-specific irregularity detection. The framework takes into account the extreme dynamics typically encountered in Upstream operations that limit standard learning models' capabilities to accurately represent and hence draw inferences about the state of the underlying system. A hybrid, adaptive, non-linear, probabilistic, reasoning model learns iteratively over multiple operating windows to identify breakouts in typical behavior and to detect ‘remarkable' divergence of reconstructed signal from original space.

The method can identify single or multiple instances of irregular activity, since the underlying causal factors, resulting in such behavior, are likely to generate a number of irregularities reflecting nonconformity to normal pattern. Unexpected sequential changes in observed system behavior can be leveraged as a first-level filter of the basic anomaly signature. Results show that applying the framework to detecting irregularity in wells operations enabled near real-time flagging of irregular patterns. An operator's adjustable alert can be set based on a threshold value of the calculated score of the streaming signal.

This new approach is a significant departure from conventional methods of establishing and using baselines for normal process behavior, such as signature-based, profiling, fingerprinting, etc., to detect anomalies. Its key advantage is that it avoids the use of single-valued thresholds intrinsic to the competing methods of the types listed above. Such single-valued thresholds have the effect of limiting the practical application of such techniques in Oil and Gas applications.
Evaluation of Completion Practices in the STACK Using Completion Diagnostics and Production Analysis
Authors: Senters C. W. , Van Sickle S. , Snyder D.
Published: September 2016

Evaluation of completion techniques continues to help in cost reduction and optimization practices. The objective of this project is to evaluate completions within Oklahoma in the STACK (Sooner Trend, Anadarko Basin, and Canadian and Kingfisher counties), comparing several types of technology and optimization methods implemented within this play.

Changes to completion practices are driven by cost reduction and production needs. When evaluating a newly implemented technique, a "science well" is often selected to run a multitude of diagnostics to verify the effectiveness of the change. The dataset in this study goes beyond the concept of a single well, or several well analysis, and focuses on approximately 50 wells in this play. Wells are categorized based on completion practices and data was gathered based on completion diagnostics. A macroscopic production analysis was completed to complement the diagnostic results.

As with any study of this magnitude, there are several variables to capture and take into consideration while evaluating the diagnostic and production data. Wells in this study are categorized to maximize the number of unchanged variables. Observations were made on the overall stimulation coverage of each treatment interval evaluated, isolation between stages completed, and trends in production. Several examples of diagnostic data are presented as case histories in addition to the categorized data set.

The STACK is one of the four most prolific plays currently being drilled and completed in the United States. This is the largest case history published on wells completed in the STACK that utilizes an integrated daily production and diagnostic approach. The dataset and case histories in this paper provide valuable insight for operators and service companies who are completing wells in this play.
Perdido - A Five Year Look at the Technologies that have Enabled Ultra-Deepwater Success
Authors: Riley Chris
Published: September 2016

Discovered in 2002, Perdido is a Gulf of Mexico frontier ultra-deepwater development, and its success has been heavily dependent on several technologies: 4-D seismic for waterflood management, PMTs (pressure monitoring transducers) for subsidence monitoring, MPD (managed pressure drilling) to mitigate narrow drilling margin, and caisson ESPs for subsea boosting. Now, five years after first oil, these technologies have matured, and each contributes to a project that exceeds initial expectations.
Collaborative Working Across the E&P Lifecycle and Evolving With New Technologies
Authors: van den Berg Frans G , Awobadejo Mayowa , van Dijk Jaap , Weiss Chris
Published: September 2016

Collaborative Work Environments (CWEs) were implemented in the majority of Shell's assets. Collaborative working has evolved beyond production and surveillance processes and has been enhanced with new mobility and visualisation technologies.
Improved RBF-Based NMR Pore-Throat Size, Pore Typing, and Permeability Models for Middle East Carbonates
Authors: Shao Wei , Chen Songhua , Cheng Yuesheng , Eid Mahmoud , Hursan Gabor
Published: September 2016

A refined radial-basis-function (RBF) method with a forward selection algorithm to improve the stability of the prediction of pore throat sizes was recently reported by the authors. Subsequently, from the pore throat size distribution data, permeability and pore typing models were developed. These models were developed with the core samples from the high-to-medium quality reservoir sections of several Middle East carbonate wells.

Because the RBF is an interpolation method, the validity of RBF based petrophysical models is enveloped by the petrophysical parameter range that the core samples represent. For economic reasons, it is common practice that core analysis be conducted on high reservoir quality rock samples because they are most important to production. To apply RBF-based models for interpreting well logging data, it is important that such models be developed with a broad range of rock qualities to help prevent misinterpreting the lower-quality formation rocks.

To expand the application envelop of the RBF based nuclear magnetic resonance (NMR) permeability models, a new set of core measurements from different reservoir quality sections, as well as non-reservoir quality sections of several carbonate wells, are added to retrain the RBF-based NMR permeability models. Standard statistical validation methods are used to demonstrate the necessity and improvements of newly retrained RBF-based models. The new models are applied to well logging data with varying reservoir quality sections, proving that the new models are adequate for better permeability prediction of all rock quality formations.
Insights on Overflushing Strategies from a Novel Modeling Approach to Displacement of Yield-Stress Fluids in a Fracture
Authors: Osiptsov Andrei , Zilonova Ekaterina , Boronin Sergei , Desroches Jean , Lebedeva Natalia , Willberg Dean
Published: September 2016

Overflushing to displace the fracturing treatment away from the wellbore and into the fracture is common in multistage completions of horizontal wells in unconventional formations, but it can damage overall fracture performance by overly displacing proppant to leave the fracture unsupported or allowing gravity slumping to occur, again leaving unpropped area. A novel modeling approach was investigated to gain insight into the process and determine reliable bounds for overflushing.

From a fluid mechanics viewpoint, overflushing is displacement of a Hershel-Bulkley fluid by a power law fluid in a Hele-Shaw cell, leading to Saffman-Taylor instability at the fluids' interface. Most hydraulic fracturing simulators use power-law rheology. A novel numerical model accounting for the yield-stress behavior exhibited by proppant-laden slurries was developed using the lubrication approximation and includes transport equations for fluid volume fractions and a nonlinear elliptic equation for pressure with mixed-type boundary conditions. The pressure equation is solved with a fixed-point (Picard) iterations method, with the multigrid linear solver used at each iteration.

The model was validated against three sets of experiments in Hele-Shaw cells: gravitational slumping, displacement of Newtonian fluids with fingering, and displacement of a yield-stress fluid by a shear-thinning fluid, leading to formation of fractal fingering patterns. Good agreement is obtained. Based on fracture mechanics, we analyzed what portion of the fracture may be left unsupported before it is severely pinched during drawdown as a reliable bound for overflushing volumes. A parametric study was focused on the displacement of the yield-stress slurry by the overflushing fluid, varying overflush volume and rate and rheology contrast between slurry and displacing fluid. Qualitatively, when fingers of the overflushing fluid can be created at the overflush/slurry interface, large slurry pillars are preserved in the near-wellbore area, which may keep the fracture open; gravitational slumping is mitigated by the yield stress. Three scenarios occur, depending on slurry rheology: from slumping-dominated (low-viscosity base fluid in the slurry), through intermediate to a fingering-dominated scenario, where gravitational convection is suppressed by high viscosity of the slurry (~1 Pa s) and considerable yield stress (>1 Pa). The third scenario minimizes the geomechanical risks of overflushing by providing tiny fingers that are unlikely to be pinched out during fracture closure.

From the study, bounds for reliable overflushing are proposed, which are a lot more restrictive when the slurry base fluid does not exhibit a yield stress (e.g., for slickwater treating fluids).
The Radial Approach to Safety Factors for Tubular Design
Authors: Liu Zhengchun , Klever Frans , Samuel Robello , Gonzales Adolfo , Kang Yongfeng
Published: September 2016

Traditionally, collapse safety factor (SF) is the ratio of tubular collapse resistance to collapse load. The collapse resistance is usually calculated using formulas suggested in API 5C3 or ISO 10400. If the collapse load is very small while the tension stress and/or internal pressure are high, the collapse SF could be very large, which is unrealistic because the load point is close to the collapse envelope. This paper presents a radial approach for the collapse SF calculation to overcome this problem. Moreover, the application of this radial approach can be properly extended to the calculation of the burst SF and the connection SF for arbitrary load combinations.

The new SF is named the "radial safety factor." It must meet the following requirement: when all the tubular loads (such as axial force, internal pressure, and external pressure) are scaled by this SF, the load point must fall exactly on the failure envelope. Therefore, for collapse, the new SF must simultaneously satisfy (1) API 5C3 collapse formulas, and (2) the through-load-point radial line equation. The Ridder's method is used to solve the SF for a specific load case. The algorithm has been implemented in a computer program and integrated with commercial software. This radial approach has been applied to both pipe body and connectors.

For burst, it is shown that the radial approach to calculate the SF is equivalent to the current method of comparing the von Mises equivalent stress to the material yield strength. An example case is used to study the effect of the radial approach on the collapse SF values. The collapse SF value is observed to become much smaller when the effective axial stress (actual axial stress plus internal pressure) is very high, which is expected because of the much-smaller radial collapse resistance (at the cross point of radial line with collapse curve). When the effective axial stress is not positive, the collapse SF slightly changes. A North Sea high-pressure, high-temperature well is also presented. The results indicate that the radial collapse SF is more realistic. In particular, it is most conservative in load cases with high effective axial stresses. The radial collapse SF has critical safety implications for load cases in which high effective axial stresses exist. Its software implementation can certainly assist well engineers with safer and more straightforward tubular design.
Multiscale Method for History Matching Channelized Reservoirs Using Level Sets
Authors: Han Jichao , Chen Rongqiang , Datta-Gupta Akhil
Published: September 2016

Identification of channel geometry, facies boundaries, and characterization of channel petrophysical properties are critical for performance predictions of channelized reservoirs. Level set methods have shown great promise to effectively parameterize facies boundaries and allow for changing channel geometry and connectivity during history matching. An outstanding challenge is efficient updating of channel geometry as well as channel petrophysics during history matching. Also, seismic data can provide important information and needs to be used as constraints.

In this paper, a novel two-step history matching workflow is proposed where the channel geometry is modeled using level sets and the internal heterogeneity within the channel facies is modeled using parameterization with linear basis functions, specifically the Grid Connectivity Transform (GCT) basis. Facies boundaries are first represented by the level set function where seismic information is incorporated and the boundaries are gradually moved by solving the level set equation under the seismic constraints. For history matching, Markov Chain Monte Carlo (MCMC) method is employed to minimize production data misfit by adjusting channel geometry and channel petrophysics.

The proposed approach is applied to both 2D and 3D examples. First, we examine the effectiveness of the level set approach by comparison with other approaches for channelized reservoirs, such as Discrete Cosine Transform and Discrete Wavelet Transform. The level set approach is shown to outperform other methods significantly in terms of reproducing channel geometry. Second, we show that the use of seismic constraints helps preserve the structure of facies distributions and geologic realism during history matching. Finally, calibrated facies models are further updated by adjusting the internal channel permeability distributions to fine-tune the history matching. The permeability changes are carried out by perturbing the coefficients of the GCT bases. High and low permeability regions are clearly depicted within the channels and production data misfit is significantly reduced during this second stage. We demonstrate the power and utility of the approach using both 2D and 3D applications.

Previous approaches focused on conditioning channelized models to well data but seismic constraints in level set were not considered. The successful integration of seismic constraints can help not only improve channelized reservoir history matching performance significantly, but also extend applicability of the level set method from simple channelized models to more complicated ones. Also, the GCT approach, for the first time, is shown to capture internal heterogeneity of the channel architecture.
Microseismic Feedback Enhanced Real-Time Diversion Evaluation in Mancos Shale, Piceance Basin Completions
Authors: Scott E. L. , Cape J. H. , Mahrer K. D. , Li N. , Childers A. R.
Published: September 2016

This hydraulic fracture stimulation case study in the Mancos Shale, Piceance Basin used real-time microseismic imaging to evaluate and guide changes to diversion strategies. The objective was to identify and improve hydraulic fracture development of three neighboring, horizontal, and parallel wells.

Black Hills Exploration and Production, Inc. (BHEP) hydraulically fractured three wells using a plug-and-perforate completion technique. All injection stages used the same treatment fluids and proppant types and differed by perforation schemes and diversion strategies. Diversion strategies included combinations of ball sealers and clean fluid sweeps (i.e., fluid without proppant), separating proppant-laden, ramped segments. Stages included one, two, or three proppant segments. The study included microseismic imaging, which acquired data using two deep geophone arrays in nearby wells. The microseismic data were processed during active injections (i.e., in real time). Following each stage, the on-site engineers compared the microseismic event distributions before and after diverters to evaluate diversion effectiveness. Differing microseismic distributions (e.g., changes in shape, azimuth, extent, etc.) combined with bottomhole pressure responses (e.g., increases and breakdowns) indicated successful diversion. Based on design, successful diversion strategies were repeated.

Normally, an on-site engineer assesses diversion success using only the bottomhole pressure response. For this project, the assessment was substantially enhanced by combining bottomhole pressure response with microseismic imaging. As a result of this strengthened assessment, the on-site engineers concluded two main results during the study: (1) ball sealers separating proppant segments led to successful diversion and (2) a clean fluid sweep or a second set of ball sealers separating three proppant segments was less effective than two proppant segments. After identifying these findings, the engineers changed subsequent stages to include one set of ball sealers separating two proppant segments.

In this study, reducing the number of proppant segments: (1) increased the stages per day by 10% and (2) increased the proppant load per fluid volume by 7%. In addition to these increased operational efficiencies and cost savings, this diversion evaluation and real-time changes improved perforation cluster efficiency (percentage of producing perforation clusters). For the three wells studied, production logs showed 3–24% greater perforation cluster efficiency than other local wells without diversion.
Further Discuss the Roles of Soaking Time and Pressure Depletion Rate in Gas Huff-n-Puff Process in Fractured Liquid-Rich Shale Reservoirs
Authors: Yu Yang , Li Lei , Sheng James J.
Published: September 2016

Cyclic gas injection (CGI), also known as huff-n-puff process, has been demonstrated as the most effective and promising IOR solution in shale reservoirs. Such process involves many operating parameters that can affect the recovery performance in different degrees. As soaking time and pressure depletion rate (PDR) are the two crucial factors, this study aims to further investigate their roles in the oil recovery process of CGI experimentally and numerically.

A total of ten series of the N2 huff-n-puff tests were performed on oil-saturated Eagle Ford shale plugs in a matrix-fracture system. With the injection pressure (Pin) of 1,000 psi, two groups of tests were conducted: 1) under a constant PDR in blowout and five soaking times changed from 0.25-hr to 48-hr; 2) under a constant soaking time of 12-hr and four pressure depletion times changed from 0.05-hr to 48-hr. With the Pin of 5,000 psi, the CGI tests were performed under 12-hr soaking time and blowout pressure depletion to study the effect of Pin on recovery efficiency. Lab-scale simulation models were built and tuned to history match the experimental data.

The experimental results show that recovery factor (RF) from a single cycle increases with soaking time within a certain range, and a longer time has no effect on improving oil recovery. For 1,000 psi Pin, during the soaking phase, the system pressure declined rapidly at the first 3 hr and then became stabilized. The pressure drop was relatively low (10 psi) in the first cycle compared with the following cycles. It tended to increase with the number of cycles performed, which was caused by the decrease of oil saturation thus more gas can be injected into the core sample. It reveals that a soaking period is necessary to the oil recovery process. On the other hand, increasing the pressure depletion rate can raise the incremental RF from each cycle. The blowout condition showed the highest cumulative RF. The performance of N2 huff-n-puff with 5,000 psi Pin outperforms the case of 1,000 psi, which can increase the ultimate RF with less cycles. The well-tuned simulation models were used to analyze and optimize the CGI recovery process.
Safe Mechanical Perforation of Pipe with Connected Control Lines
Authors: Denmon Michael , Harive Kevin , Babin Jacques
Published: September 2016

Currently, oil and gas operators face a number of significant challenges, such as meeting increasing demand and using safe and environmentally responsible methods as well as minimizing costs while maximizing the profitability of highly complex operations.

One solution is to achieve a more comprehensive understanding of assets by successfully integrating monitoring and active control systems. This led to the implementation of smart-well completions (i.e., interval control valves, interval control devices, subsurface safety valve systems, and fiber optic monitoring) (Rodriguez et al. 2013).Yet, some companies still resist this technology because of risk concerns, such as valve failures occurring or bypassed pay zones that warrant well intervention being necessary, which involves pipe perforation. When a control line or umbilical line is strapped to the outside of a well completion, risk is increased for the well intervention. In most instances, it is not possible to pinpoint the exact location of the line within a 360° span of the curvature of the tubing. This is because some completion designs without pre-planned indicators of line placement add to the challenges associated with control and data line moving during the running phase of the well completion. Without the ability to locate the line used for communication with downhole devices, the potential for damage exists resulting from conventional methods of explosive perforation. The development of a nondamaging perforation method provides a means to establish needed communication while helping avoid unrecoverable damage to an asset.
Continuous Microfacies Analysis in Clastic Environments Utilizing Pseudo Grain Size Distribution from Electrical Borehole Images
Authors: Yang S. , Aviantara A. , Delius H. , Le Nir I. , Gong H. , Wang K.
Published: September 2016

Sediment particle size and its distribution are fundamental attributes of sedimentary deposits that provide key information for reservoir quality evaluation. Traditional grain-size analysis can only be obtained from laboratory testing on rock samples from cores. In the absence of core or suitable cutting information, borehole images and nuclear magnetic resonance (NMR) logs are basic input data to estimate grain size. Recently several approaches were proposed for grain-size analysis from NMR for depositional environment studies and expandable sand screen design. In this paper, we propose a new approach for the continuous microfacies analysis from pseudo grain-size distribution of borehole resistivity images.

The true size of particles is very difficult to be measured directly from borehole resistivity image, especially when the particle size is less than the tool button size; additionally, correction factors are different for conductive and resistive particles depending on the resistivity contrast. Based on the high resolution resistivity image, we assume that the resistivity of multiple button measurements represents the particle size relatively, similar to the principle of analyzing textural changes within clastic environments using electrical borehole images. The cumulative probability of each resistivity curve represents a similar statistic to that of grain size in laboratory experiments and indicates the different hydrodynamic conditions. In certain geological settings, the continuous microfacies analysis can be achieved from the cumulative frequency curve shape.

Several case studies were performed to verify this new approach in different depositional environments, including a fluvial system, a lacustrine delta and an aeolian deposit. The analysis results are consistent with drilling core data and provide the detailed microfacies information for sand unit correlation analysis in multiple wells. We find this method is robust in the fluvial system and conglomerate-related depositional environments, and but it is very challenging to distinguish the mouth bar and channel fill in a river-dominated delta.
Drilling with Casing Technology Eliminates Wiper Trips, Lost Circulation, Water Influx, and Wellbore Stability in Two Continuous Sections, Saving up to Five Days in Northern Bolivia
Authors: Ibañez Julio C. , Aguirre Edwin C. , Pinto José E. , Tan Ming Zo , Mendez Marco A.
Published: September 2016

This paper discusses the planning process, execution, and results of casing-while-drilling (CwD) operations in northern Bolivian fields that are historically plagued with problems of water influx, wellbore instability, lost-circulation, and severe bit wear. This paper will discuss why the selection of drillable casing bits is critical to ensuring successful drillout of the same type of polycrystalline diamond composite (PDC) casing bit.

Formation drillability and suitability of well designs in targeted problematic fields, namely Yapacaní, Cobra, and Sirari, are also analyzed to ascertain whether CwD is a viable solution to tackle drilling challenges. A collection of conventional drilling data for six oil wells was provided for the analyses. At the end of the project, CwC technology successfully reduced operational time by 70% on average by improving drilling efficiency and mitigating drilling hazards.
Multi-thermal Fluid Assisted Gravity Drainage Process to Enhance the Heavy Oil Recovery for the Post-SAGD Reservoirs
Authors: Dong Xiaohu , Liu Huiqing , Zhang Zhaoxiang , Wang Lei , Chen Zhangxin
Published: September 2016

Multi-thermal fluid is a new type of heat-carrier proposed in recent years for the EOR process in heavy oil reservoirs. Compared with the conventional saturated-steam injection process, multi-thermal fluid injection technique combines the multiple advantages of im/miscibility gas injection and thermal recovery. In this paper, based on the multi-thermal fluid injection process and the conventional steam-assisted-gravity-drainage (SAGD) process, a new thermal gravity-drainage process, multi-thermal fluid assisted gravity drainage (MFAGD) technique is proposed to enhance the heavy oil recovery for the post-SAGD reservoir. From the dimensionless scaling criterion of gravity-drainage process, two 3D gravity-drainage experiments (SAGD, SAGD-to-MFAGD) are firstly conducted to explore the EOR mechanisms of multi-thermal fluid in heavy oil reservoirs and oil sands. Subsequently, numerical simulation has been performed to match the experimental measurements. Then, from the scaling criterion, these lab-scale reservoir properties are converted to field-scale. Thus, a field-scale numerical model is developed. From this field-scale numerical model, the difference of SAGD process and MFAGD process are discussed. The reservoir adaptability of MFAGD process are investigated, and the operation parameters are numerically optimized.

Experimental results indicate that a strategic combination of SAGD process and MFAGD process could tremendously improve the development of heavy oil reservoirs. And MFAGD process can be adopted as an additional recovery stage for the heavy oil reservoirs after SAGD process. For the mechanisms, with the exception of the conventional thermal recovery mechanisms of steam injection, it is shown that the mechanisms of heat insulation, energy recovery, gas dissolution, foamy oil and auxiliary cleanup are also important for this new thermal gravity-drainage technique. From the lab-scale numerical results, the injection of multi-thermal fluid further unify the chamber profile along the horizontal wellbore. The field-scale numerical results show that compared with the performance of SAGD process, MFAGD process has lower steam consumption and lower cSOR. The steam chamber after MFAGD process is shaped like "liquid drop" instead of the conventional "inverted triangle" shape of SAGD process. In order to obtain a better performance for the MFAGD process in post-SAGD reservoir, the value of Kv/Kh should be not less than 0.3; the reservoir thickness should be not less than 30 m; and the value of NTG should be not less than 0.7. For MFAGD process, the optimal gas/steam ratio (standard condition) is 1:1, steam injection rate is 200 m3/d, and the chamber operation pressure is 3.0 MPa. This paper further deepens the understanding of the EOR mechanisms of multi-thermal fluid injection process in heavy oil reservoirs and oil sands. The proposed MFAGD process will be a significantly potential EOR method for the post-SAGD reservoir.
Novel Method for Evaluating Shale Gas and Shale Tight Oil Reservoirs Using Well Log Data
Authors: Freedman Robert , Rose David , Sun Boqin , Brown Ronald L. , Malizia Thomas
Published: September 2016

This paper introduces a novel method for improved evaluation of shale gas reservoirs, shale tight oil reservoirs, and immature organic shale source rocks. The method provides exact and original algebraic equations for determining total porosities, producible fluid volumes, total hydrocarbon volumes, kerogen volumes, and immobile hydrocarbon volumes. The determination of accurate porosities and fluid volumes in organic shale reservoirs is critical for formation evaluation considering the low porosities (3 to 8 p.u.) typically found in shale reservoirs.

We analyze the challenges associated with interpreting logging tool responses in poor quality shale reservoirs and propose a suite of logging tool measurements that are most likely to overcome the problems. A small set of logging tool measurements (i.e., three or four) that have known responses to fluid and solid volumes and have negligible surface effects were selected. Thus our approach aims to circumvent the interpretation problems caused by poorly understood complex fluid-surface interactions that are exacerbated in shales by high surface-to-volume ratios and clays and other conductive minerals.

The logging tool measurements that we use to predict the shale reservoir properties are bulk densities, nuclear magnetic resonance (NMR) porosities, and total organic carbon (TOC) weight fractions derived from total carbon concentrations measured by a gamma ray spectroscopy tool. The tool response equations for these measurements are written as volume weighted averages of reservoir properties. The producible gas in shale gas reservoirs and the high API gravity producible oils in shale tight oil reservoirs cause the apparent (i.e., measured) NMR porosities to read too low and the apparent density log porosities to read too high. Kerogen also causes the density log porosities to read too high.

The tool response equations are solved simultaneously and exactly to determine shale total porosities, fluid volumes, and kerogen volumes. The solution for the shale total porosity is automatically corrected for light hydrocarbon effects on the density and NMR porosity measurements and for kerogen effects on the density porosities. The exact algebraic solutions or "plug-in formulas" for shale reservoir properties are the main results of the paper. The robustness of these solutions in the presence of measurement noise is studied using Monte Carlo simulations. We discuss the standard deviations of the predicted reservoir properties for different measurement noise levels and the effects of errors in the assumed reservoir fluid and solid properties (e.g., gas density, gas hydrogen index, kerogen density) on the accuracies of the predicted reservoir properties.

The algebraic solutions are used to predict reservoir properties from log data acquired in a shale gas well and a shale tight oil well. The results in both wells are shown to compare favorably with available core data.
New Insights on Chemical Diversion in Carbonate Acidizing: Experimental and Simulation-Based Study
Authors: Nino-Penaloza Andrea , Gomaa Ahmed M.
Published: September 2016

Carbonate acidizing restores and enhances production by dissolving a fraction of the rock to create highly conductive channels or wormholes. Most experimental acidizing studies are focused on acid injection at Constant Volumetric Rate (CVR) rather than at Constant Injection Pressure (CIP). A recent study highlighted the benefits of each injection technique for 15% wt. HCl acid. Formations with high injectivity should be treated at CVR as efficient wormholes can be propagated with less acid volume. Aditionally, the increasing injection rate characteristic of CIP can be beneficial in formations with initial low injectivity where wormhole dissolution can change from face and conical to dominant pattern.

The injection rate and injection pressure for acid and chemical diverters are important variables because they affect wormholing, treatment distribution, and therefore the overall skin reduction. The primary objective of the present work is to investigate the effect of chemical diversion when acid treatments are injected at CVR and CIP. This study focused on the behavior of a Viscoelastic Surfactant (VES) based acid diverter inside the porous media and its effect on the treatment and wormhole distribution for low and high injectivity formations.

A core-flood study was conducted using Pink Desert Limestone cores with similar permeability to assess the pressure response of the diverter at CIP. Additionally, a 2-D wormhole model was used to describe the acidizing phenomena. This model captures the acid reaction and chemical diversion coupled with Darcy flow. Synthetic scenarios were created to evaluate the effect of each acid injection technique (CVR and CIP) and diversion staging on the post-treatment skin and wormhole length.

The results of these simulations showed that proper staging of a the chemical diverter aided to improve the treatment placement injected at CVR in a long, highly permeable and homogenous zone as shown by smoother wormhole and skin profiles. CIP delivered nearly uniform treatment placement without chemical diverter when applied at the highest rate below fracture pressure in a long, homogenous and low permeable zone.

For a synthetic case of a long and heterogeneous treatment zone, this study confirmed that CIP generated branched wormholing in the high-permeability zones in the early stages of a treatment sequence and did not significantly reduce the skin in the low injectivity layers. Fluid placement turned less efficient as the injection rate increased over the course of the treatment. Based on these results, the simulation outputs suggest that CIP is not an effective diversion technique in long treatment intervals with significant injectivity contrast. Additionally, it was observed that the inclusion of diverter stages can improve the treatment distribution.
Increased Capabilities for Upward Recomplete of Remote Platform Wells
Authors: Denmon Michael , Harive Kevin , Clemens Jack
Published: September 2016

Through-tubing bridge plugs (TTBPs) enable the production of new zones by isolating abandoned zones without requiring a costly and time-consuming workover rig. Previously available hydraulic setting tools were not applicable to all types of well conditions and plugs, often because of extended toolstring length requirements, making them not suitable for wells with limited rigup height capability. A nonexplosive electromechanical setting tool can provide an easy-to-transport, flexible setting tool for all environments.

An electrically controlled motor enables the effective setting of multiple sizes and types of TTBPs, not dependent on the environmental effects on downhole fluid required by hydraulic tools to facilitate the setting process. The tool uses rotational torque converted to linear pull tension and operates independently of downhole conditions, not requiring specialty fluid types or relying on the appropriate fluid availability. Because fluid is not required for operations, a shorter overall tool length is required compared to existing hydraulic or pneumatic tools. The ability to deploy shorter toolstring lengths means that the electromechanical setting tool can be used in a wider variety of scenarios, such as remote platforms or rigless environments.

With the introduction of the electromechanical setting tool to operations, wells that might have been previously suspended because of the availability of a workover rig can now receive timely interventions, efficiently isolating noncontributing zones and enabling the perforation and production of contributing zones. Operators can benefit from rigless operations by accessing new zones at a lower cost and with a faster turnaround, enabling them to benefit from economically advantageous market conditions. The real-time feedback of the electromechanical tool also confirms that the plug has been set at the required tension using a slow and controlled setting method.

This paper presents case histories to illustrate the advantages of the shorter rigup lengths enabled by the electromechanical setting tool; these advantages are made possible by pinpointing instances in which the hydrostatic setting tool methodology would not have allowed recompletion of producing zones. Job data from the electromechanical setting tool are used to illustrate that the slow, controlled set of the TTPBs was achieved within specifications of the plug design, which cannot be confirmed using hydrostatic setting tools. Cost savings and realized production gains are also highlighted in instances in which the electromechanical setting tool was used to increase asset return value.
Application of Reservoir Characterization Synthetically Applied With Ant Tracking and Geological Statistics Inversion in Offshore Oilfield Development: A Case Study of CFD11-X Oilfield in Bohai Bay Basin
Authors: Wei Yang , Qingyun Bai , Peng Meng , Guangming Pan , Chuanqi Liu
Published: September 2016

CFD11-X is an offshore oilfield in Bohai Bay Basin. Since the drilling data is less and the resolution of seismic data is not high in the deep, our knowledge to the fault system and sand bodies is not sufficient. During the implementation of overall development plan (ODP), it gradually exposes the problems that the prediction errors of sand bodies and fluid system are serious for some development wells and the geologic risk is underestimated. These problems make the ODP less effective and cause some wastes of investment directly.

To solve the problems, the authors applied ant tracking algorithm and geological statistics inversion synthetically in reservoir characterization study. On one hand, we apply ant tracking algorithm to identify the faults which are too complex and indistinct to be interpreted manually. On the other hand, we apply geological statistics inversion to describe the distribution of sand bodies. After that both the faults and sand bodies are extracted and overlaid together. By use of multiple materials and methods, we analyze every fault to classify and screen them in both "possibility of existing" and "influences on oil in place and oilfield development" aspects. With the new perception of fault system and sand bodies, we build geological models to improve the geologic risk prediction. Finally under the guidance of our study, both the geologic risk and potential of each well to be implemented in ODP are reevaluated and optimized. Recently we choose two of the wells as pilot tests. It is confirmed by the two wells that our prediction of the sand bodies and fluids are both quite accurate with the guidance of reservoir characterization study.

In the context of the current low oil price, our study effectively reduces the cost of development, decreases the investment risk and increases the return of investment.
Transforming the World of Asset Management in Near Real-Time Using an Intelligent Application to Optimize Daily Production Operations
Authors: Gupta Supriya , Kansao Rami , Saputelli Luigi , Escorcia Alvaro
Published: September 2016

Operators nowadays are swimming in huge terabytes of data through continuous data acquisition and permanent reservoir wide surveillance but will little intelligence to identify and decrypt key obstacles, challenges and constraints to sound asset management. Silo-ed organizations and short-term blindness offer limited opportunities to understand reservoir performance in real-time and its associated challenges and therefore minimize opportunities for production enhancement and value creation. This paper discusses a novel application which can help E&P operators in implementing best practices towards continuous monitoring of daily production operations to better understand and address key issues related to production performance from upstream to mid-stream. It offers a unique data-model coherent with Petroleum Production Data Management (PPDM) guidelines, built-in logic to determine actionable key performance indicators (KPI's) to measure asset performance, and interactive and collaborative dashboards to identify key challenges and bottlenecks to sound asset management and opportunities to enhance production and improve operational efficiency. The proposed visual solutions can decrypt constraints from reservoir to surface and mitigate these challenges by discovering and diagnosing the issues in real-time. In this manner, this application can facilitate exception based surveillance which is becoming an integral part of operating philosophy for E&P companies (Kumar 2013). It was proven that this application helped reservoir and production engineering teams achieve higher success in production transformation initiatives for capturing daily operations which are not detectable by traditional engineering analysis and reservoir simulation production forecasts.
Carbon Quantum Dots Fluorescent Tracers for Production and Well Monitoring
Authors: Murugesan Sankaran , Kuznetsov Oleksandr , Suresh Radhika , Agrawal Devesh , Monteiro Othon , Khabashesku Valery N.
Published: September 2016

Tracer technology is a very efficient diagnostic tool for the oil and gas industry to obtain valuable information about reservoirs. The interpretation of tracers that have traversed the reservoir reveals reservoir characteristics such as inter-well connections, heterogeneities, and water movements that can be used to improve hydrocarbon recovery efforts. Commonly used tracers are radioactive elements and stable isotopes, chemicals, such as fluorescent dyes, and inorganic ions. Novel carbon quantum dots (CQDs)-based fluorescent tracers have been proposed for production and well monitoring. One-step electrochemical synthesis of CQDs from low molecular weight chemical precursors through electrochemical carbonization was developed. The doping of CQDs with heteroatoms such as nitrogen provides differentiated fluorescence emission signatures that can be used to monitor multiple stages of frac operations.
Pushing to the Extreme—Microseismic Monitoring of Hydraulic Fracturing in an HP/HT Horizontal Well in the Sultanate of Oman
Authors: Briner Andreas , Nadezdhin Sergey , El Gihani Mahmoud , Al-Wadhahi Taimur , El-Taha Yasin Charles , Harrasi Othman , Kelkar Shrihari
Published: September 2016

In the last 3 years, Petroleum Development Oman (PDO) went from failure to success with microseismic monitoring of hydraulic fractures in deep, high-pressure/high-temperature (HP/HT) horizontal wells. The most recent operations were performed in the conditions of the highest complexity to date.

The hydraulic fracture monitoring (HFM) was performed in the 69° deviated section of a horizontal well with the geophones conducted on wireline. The perforation shots for velocity model calibration were performed through casing with no cement behind (a feature of the treatment well completion), which has not previously been documented in publication. A new generation of microseismic geophone shuttles was used on the stinger with two knuckle joints to enable passing through the high-dogleg sections of the well.

The geophones spent up to 12 hours downhole in one run with no signs of failure. The sensor array was successfully deployed on the first attempt in all runs in the highly deviated well section. Four fracturing stages were monitored, yielding hundreds of good-quality microseismic events. This provided enough data to evaluate the fracture geometry and complexity, symmetry of fracture wings, diversion efficiency of swell packers, and the number of fractures initiated in the same stage and their propagation. All this provided input for meaningful comparison of the openhole completion with previously completed cased holes. This data will guide future field development, well count, well spacing and will enhance the fracturing design of any future wells.
Hydraulic Fracturing Treatment Design Considerations for Effective Proppant Pillar Construction
Authors: Gomaa Ahmed M. , Hudson Harold , Nelson Scott , Brannon Harold
Published: September 2016

As an alternative to conventional proppant pack placement, propped pillar-fracturing promises more effective and conductive fractures that enable hydrocarbons to flow through open channels. Recent experimental and numerical studies confirmed that viscous fingering phenomena can be used to develop a proppant pillar-fracture type placement: High-viscosity, proppant-laden fluid can be placed, and then a low-viscosity clean fluid is pumped to carve pathways through the proppant-laden fluid in a dynamic, continuous process. However, the created channel pattern was found to be significantly dependent on fracture geometry and treatment design parameters such as injection rate, fluid pulsing time, and fluid viscosity ratio.

The objective of this study is to extend the numerical investigation and normalize it to develop a treatment design methodology for constructing proppant pillars throughout the created fracture. A computational fluid dynamics (CFD) model was constructed using commercial CFD software, simulating the flow of fluids inside the fracture and the resulting proppant pillar generation. The study focused on the effects of surface injection rate (1 to 40 bpm/cluster), pulsing time (5 sec to 5 min), and viscosity ratio (from 2 to 20) between the two injected fluids to develop correlations between these parameters and the created fracture geometry.

Based on numerical results, the viscosity ratio chosen to achieve the proppant pillars allows the use of conventional crosslinked fluid without a hindered settling agent. In these designs the settling of proppant into pillars can be made to occur after the end of the stimulation treatment. Controlled settling of proppant from a crosslinked proppant-laden slurry allows channel formation and creates wider propped fracture-width pillars as compared to current industry pillar-fracturing treatment techniques. The optimum channel pattern has small channel sizes, remains open under closure stress, creates more channels throughout the entire fracture area and maintains good communication between unpropped areas. A new dimensionless term, Dimensionless Stage Volume (VSD), is presented to describe the channel pattern inside the fracture. Smaller VSD numbers resulted in smaller and more distributed channels. Therefore, it is highly recommended to select and design a proppant pillar-fracture treatment to achieve the lowest VSD possible and create the optimal channel pattern.