bluuebunny/crossref_metadata_2025 huggingface dataset:
Synergistic Effect Between Wormlike Micelles and Nanoparticles in Stabilizing Foams for High Temperature Stimulation
Authors: Zhu Jingyi , Yang Zhaozhong , Li Xiaogang , Wang Zexun , Lu Yanjun
Published: October 2018

As the resulting foam is unstable both thermodynamically and kinetically, its volume decays with time once foam generation is stopped. Lack of stability of these foams often limits their application. The current study attempts to investigate the synergistic effect of using elongated wormlike micelles and silica nanoparticles on foams stability. And foams with better performance as a fracturing fluid can be conducive to efficient stimulation under harsh formation conditions.

First, the stability of static foams was studied using a blend of cationic foaming agent (CTAB) and wormlike micelles zwitterionic surfactant (EAPB) with and without silica nanoparticles. Second, in order to figure out the stability mechanism, bubble size distribution, film thickness, micro structure were conducted by optical microscope and cryo-scanning electron microscopy (cryo-SEM) while free drainage, viscoelasticity and rheology experiments were carried out for confirming the conclusion. Finally, proppant suspension experiment with silica nanoparticles over time was measured at high temperature to verify the synergistic effect between elongated wormlike micelles and silica nanoparticles.

With silica nanoparticles and elongated wormlike micelles, foams exhibited a significant improvement in stability especially at high temperature. As the three main mechanisms operating during and after the production of foams are drainage, coalescence and coarsening, irreversible adsorption on gas-liquid interface of silica nanoparticles could improve the elasticity of foam films and elongated wormlike micelles could enhance the fluid viscosity at the same time. They remarkably delayed above three processes, showing synergistic effect in stabilizing foams, corresponding to uniform and small bubble size, thick foam films, dense micelle structures and slow drainage rate. Under high temperature and shearing stress, the viscosity of foam began to rise at first which may result from the network formation consisting of micelles-nanoparticles junctions. This corresponded to an increase in viscoelasticity when adding silica nanoparticles. However, once association between micelles and silica nanoparticles broke, there was a continued decrease in viscosity. The proppant suspension experiment showed that although free drainage stopped and foams became unstable, the presence of nanoparticles aggregates together inducing traffic jam in Plateau border, slowing the drainage rate which dominates the velocity of settling proppant. Therefore, the settlement of proppant could be hindered because of physical resistance of nanoparticles.

With enhanced performance, foams employed as a fracturing fluid exhibit extraordinary characteristics in terms of stability, rheology and proppant suspension ability at high temperature. It is worth pointing out that nanoparticles will have a broad prospect in stimulation field.
Pre-Loads: Successful Mitigation of Damaging Frac Hits in the Eagle Ford
Authors: Whitfield Tom , Watkins M. Hunter , Dickinson L. James
Published: October 2018

Although infill drilling and tighter well spacing have improved the production and economic return for North American Shale leases, these practices have intensified a problematic side effect often referred to as Frac Hits (Jacobs 2017). Frac hits occur when a new ‘child’ well is completed near an already producing well and the frac treatment interacts with the older parent well, usually resulting in either total loss of production or diminished producing capacity (King et al. 2017). In some fields, such as the Haynesville, frac hits have been reported to improve parent well production (Esquivel & Blasingame 2017). However, as these wells produce longer in to their life cycle, that positive impact is less certain to result in a long-term recovery improvement. In the past, the loss of the parent well was not associated with a significant loss in production compared to the new wells. However, with increasingly larger completion designs executed on wells spaced ever closer together, the impact of frac hits has grown substantially in the past few years (Daneshy 2017; Rainbolt & Esco 2018).

Frac hits are not a new phenomenon in the development of North America's Shale fields. Usually first encountered by operators during the progression from Hold By Production (HBP) to infill drilling, they have been widely documented and studied over the past 6+ years. However, apart from avoiding frac hits entirely through a fully integrated field development plan, the existing industry literature does not provide a flexible, repeatable, cost effective solution to mitigating frac hits. Refracs have been discussed for parent wells next to the new infills, but economics have been difficult to justify on more recently completed wells with larger completion designs, and refracs do not address the challenge of third or higher generation infill activities where several wells are at risk of being frac hit.

This document will cover the development of the frac hit mitigation technique that the authors developed in their company's Eagle Ford acreage and which is now employed as standard practice for all infill completion campaigns in both the Eagle Ford and Permian.
Well Intervention Program Creation at the Novoportovskoye Field
Authors: Olender Oleg , Malyugin Andrey , Fedotov Vladimir , Korepanov Alexander , Asmandiyarov Rustam , Zulkarniev Rustem , Studinsky Roman , Sayfutdinov Elnar , Ivanov Anton
Published: October 2018

Novoportovskoye Field is classified as large and is characterized by complex geological structure, reservoir development is complicated by bottom water and gas caps.

The field is developed by horizontal wells with a horizontal section length of up to 2,000 m and various completion methods: Assemblies with extended screen sections isolated by packersAssemblies with sliding ball-activated hydraulic fracturing collarsInternal-flush assemblies with hydraulic fracturing collars (30pcs) activated by a special CT-conveyed device.

To estimate the efficiency of multi-stage hydraulic fracturing in horizontal wells, a module has been developed that allows estimating the effect of the primary and repeated fracturing. The module takes into account the increase in the number of frac stages, fracture half-length and width, it allows to estimate the risks of clay barriers breakthrough, evaluate reservoir properties, and select the stimulation option.

To select wells for Hz sidetracking and infill drilling, an algorithm for identifying undeveloped reservoir sections was applied to evaluate the efficiency of well interventions and assess the risks in each zone.

In the conditions of oil rims, to increase the efficiency of reservoir development using horizontal wells with screen completions, it is recommended to use casing packers in a liner assembly that divide the horizontal borehole into isolated sections. This solution will allow to perform targeted isolation / stimulation of a certain horizontal interval in the process of well operation in case of a decrease in productivity and water/gas breakthrough. As a result, the cost-effective life of a well will be extended and the oil recovery factor of the field will be increased.

A twin-packer technology for a targeted stimulation of a certain interval in a horizontal wellbore was tested and successfully implemented by Gazpromneft-Yamal.
An Investigation of Proppant Transport in Friction Reducer Fluid Systems Utilizing a Large Slot Flow Apparatus
Authors: Drylie Stephen , Duenckel Robert , Barree Robert , Hlidek Barry
Published: October 2018

Current unconventional reservoir development depends on an assumed network of induced fractures created by hydraulic fracturing operations that facilitate production. In many cases natural fractures are linked to the created fractures and also contribute to production. Only in some fraction of the created and natural fracture network will proppant have been placed during the fracturing operation. In order to model the production from these fracture systems, reservoir and completion engineers often make optimistic assumptions about propped fracture half-lengths based on inaccurate expectations regarding proppant transport and proppant pack behavior. This work addresses proppant transport behavior by presenting results from large-scale lab testing of proppant transport with a range of fluid rheologies utilizing a slot flow apparatus.

Proppant transport tests were performed at multiple rates and proppant concentrations utilizing a 4-foot by 16-foot fracture slot. The primary testing objective was to compare proppant transport in friction reducer (FR)-based fluids against previously published results and other work that has been performed in this apparatus. Additional tests using guar based fluids of a similar nominal viscosity will be used for comparison and to demonstrate the need for other rheological properties for planning and predicting completion results.

The results of this testing will provide a more realistic description of proppant transport. Through this enhanced understanding, reservoir and completion engineers will be able to make improved assumptions about propped fracture dimensions that will drive better decisions regarding fracture design, improving recovery, optimizing spacing, and field development while reducing the need for costly future interventions and refracturing treatments. After an introductory review of important conclusions from previously published work performed in this and other slots, the results of this testing will be used to evaluate the validity of these conclusions. Additionally, relationships and interactions between viscosity, rate, proppant concentration, and other fluid properties will be established and reviewed to facilitate the development of improved models for proppant transport in unconventional reservoirs.

Much of the earlier lab work performed in slots of this scale was performed when crosslinked fluids were the preferred fluids in almost all applications. Since that time, the industry has shifted to a preference for slickwater fluids and other systems of much lower viscosity in the hope that increased velocity would make up for the loss in viscosity. This work will highlight where this hope is unrealized and when other fluid properties make the drop in viscosity less important than expected.
Hydraulic Fracturing Optimization for Regions with a Complex Tectonic Regime, High Temperature and Abnormal High Pore Pressure Conditions, in a Karatobe-Burbaital Well No. 101, The Caspian Depression
Authors: Nizametdinova Madina , Iskakov Askar , Zavarygin Sergey
Published: October 2018

This article is devoted to hydraulic fracturing justification, risks estimation and fracture optimization for ultra deep wells in regions with a complex tectonic regime, high temperature and Abnormal High Pore Pressure (AHPP) conditions, using the example of Karatobe-Burbaital well No. 101, The Caspian depression.

An approach was used to optimize well stimulation by hydraulic fracturing. Optimization is based on 1D Mechanical Earth Model and core tests results for petrophysical and mechanical rock properties. The model considers the thermal effects which influence on perforations and stress distribution around the borehole. The drilling and well development histories are used in the modeling.

Based on the geomechanical model results a complex tectonic regime has been identified involving the fracture propagation in both vertical and horizontal planes. The conducted complex analysis showed the presence of a hydrodynamic connection with the underlying water-saturated layer. Hydraulic fracture program was optimized accounting geological conditions, equipment technical limitations and multi-layer reservoir, with the risk that one fracture might be propagated into the underlying water-saturated formation. According to the stimulation program the fracture geometry was determined and starting rates were estimated. This allowed to determine the hydraulic fracture possibility and well stimulation feasibility underthese conditions.

Successful hydraulic fracturing in regions with a complex tectonic regime, high temperature and AHPP conditions requires a comprehensive optimization approach based on an accurate geomechanical model.
Employees Adaptation Mechanisms in Extractive Industries while Shift Work Organization at Far North and Arctic
Authors: Yurjeva Anna , Korneeva Yana
Published: October 2018

The study was carried out with the financial support of the grant of the President of the Russian Federation for state support of young Russian scientists - candidates of science (MK-6409.2018.6). The article is devoted to the description of the mechanisms of psychological adaptation of employees of oil and gas producing companies of various professional groups during shift work organization in the Arctic.

Mining industries are located in remote areas of the Far North and the Arctic, which is why the shift work method is used there. The professional activity of shift work specialists in the conditions of the Far North presents high demands for the creation of conditions for physiological, psychological and socio-psychological adaptation.

Despite the large number of works in medicine and psychology devoted to these issues of human adaptation to severe climatic and geographic conditions and shift work, the systematization and classification of the mechanisms of psychological, social and psychological adaptation of workers in extractive industries is not enough.

The research was carried out in oil and gas production with a shift work organization on the territory of the Nenets Autonomous Okrug (the duration of the rotation arrival is 30 days). The study involved 70 workers aged 24 to 60 years (mean age 38.7 ± 1.3). Methods of research: studying documentation, monitoring the work process, questioning, psychophysiological and psychological testing, statistical methods of data analysis.

As a result of the research, differences in self-regulation, regulatory processes, psychological protections and mechanisms of socio-psychological adaptation among workers in the oil and gas production of various professional groups were revealed.
Large Scale Field Development Optimization Using High Performance Parallel Simulation and Cloud Computing Technology
Authors: Tanaka Shusei , Wang Zhenzhen , Dehghani Kaveh , He Jincong , Velusamy Baskar , Wen Xian-Huan
Published: October 2018

Field development optimization for oil and gas reservoirs is typically challenging due to large number of control parameters, model complexity, as well as subsurface uncertainties. In this study, we propose a joint field development and well control optimization workflow using robust parameterization technique and demonstrate its application through a offshore oil field development.

Traditionally, using simulation models for optimization of field development plan was considered time and cost prohibitive when incorporating models to cover range of uncertainties in reservoir properties. Consequently, the problem was simplified by reducing the number of control parameters through multi-disciplinary workflows. In this paper, we aim to optimize field development strategy by simultaneously controlling topside facility, number of wells, their trajectories, drilling sequence, and completion strategy etc., considering subsurface uncertainties and constraints. To achieve this, we used our next generation reservoir simulator and commercial cloud computing to explore the possibility of achieving an optimized development scenario within reasonable time and cost constraints.

We have applied the proposed workflow to the Olympus field case, which is an optimization benchmarking problem set up by Netherland Organization for Applied Scientific Research (TNO) using a synthetic North-sea type reservoir. Our objective is to improve the net present value (NPV) after 20 years of operation by controlling the number and location of platforms, number of injectors and producers as well as their trajectories and drilling sequence. The large number of control parameters and subsurface uncertainties make the optimization process challenging. Three optimization techniques, genetic algorithm (GA), particle swarm optimization (PSO) and ensemble-based optimization (EnOpt) were tested and their performances were compared. Best results in terms of NPV improvement was obtained by using the mixed-integer Genetic Algorithm method. More than ten thousand simulation runs were required by the method to reach to optimal development of well location, trajectory, drilling sequence etc. This was made possible by utilizing a high performance parallel simulator and cloud computing. The estimated cost of the commercial cloud service is almost negligible compared with the improvement in the economic value of the optimized asset development plan. The developed workflow and parameterization technique are flexible in well trajectory configuration and completion design allowing application to primary depletion as well as waterflooding.
Increasing of Operation Efficiency of Low Pressure Gas Wells by Using of Gas-Jet Device's
Authors: Fedorov Aleksei , Ibatulin Artur
Published: October 2018

One of the most important tasks in the development of multi-layered regions with a cluster layout of wells is to increase the low-pressure wells operation efficiency. A successful solution of this task can, in particular, help to increase the efficiency of developing multi-layer deposits by developing reserves of low-potential deposits, as well as reducing the time spent on producing reserves.

This task is relevant both in the development of oil and gas fields. And the situation is complicated at the late stage of field development. Inactivity of wells leads to loss of production, uneven development of productive layers and poor performance of fields development.

As a solution to the presented problem, in this paper, it is proposed to use gas-jet devices (GJD) to reduce the wellhead pressure of wells, which allows to jointly operate high-pressure and low-pressure wells in conditions of limited infrastructure.

This paper presents the results of the field trial of the developed method and the technological scheme for reducing the wellhead pressure of gas wells [5], [8], tested on gas wells at the Gubkinskoe field of LLC Rosneft-Purneftegaz. The tests were carried out with a positive result. An assessment was made of the further expediency of using GJD to improve the development efficiency of the Gubkinsky multi-layer field.

Based on the data obtained from the field trial, the prospects for further development of the technology for increasing the operation of gas condensate wells (in conditions of inefficient mechanization) and increasing the efficiency of oil wells (gushing and mechanized) are developed.

To solve these problems, the authors of the work used the results of theoretical and experimental studies of sonic GJD with the cylindrical throat conducted on special stands in laboratory of techniques and technology of oil production in Gubkin Russian State University of Oil and Gas (National Research University) [5].
Development of Surfactant-Polymer SP Processes for High Temperature and High Salinity Carbonate Reservoirs
Authors: Ghosh Pinaki , Sharma Himanshu , Mohanty Kishore K.
Published: October 2018

Oil recovery during waterflooding of carbonate reservoirs is often low due to their oil-wetness and heterogeneity. Surfactant-Polymer (SP) flooding can improve the oil recovery from these reservoirs through ultra-low interfacial tension (IFT), mobility control and wettability alteration. However, there are several challenges associated with this process in high salinity and high temperature carbonate reservoirs related to thermal stability of polymers at elevated temperatures, compatibility of surfactants with high concentration of divalent cations present in formation brines, and geochemical interactions with carbonate minerals. This paper addresses the following challenges: surfactant interaction with formation brine containing high concentration of divalent cations and thermal stability and transport of polymers in carbonate rocks at a high temperature (80 C). Surfactant phase behavior experiments were performed to identify promising surfactant candidates which showed ultralow IFT with crude oil and aqueous stability at high temperature in high salinity and high hardness brines. A systematic study was performed to understand the effect of surfactant hydrophobe length on phase behavior, oil recovery, and surfactant retention in coreflood experiments. Novel surfactants with very short hydrophobes and cosolvent-like properties were also included to further optimize the phase behavior. Surfactants of larger hydrophobe length, containing similar number of EO and PO groups, gave higher solubilization ratio (and lower IFT) and lower optimum salinity. Specialty synthetic polymers with good thermal stability and salinity tolerance (TDS > 90,000 ppm) were investigated for their transport in single-phase corefloods. Results showed successful transport of polymer, without degradation in-situ, and improvement in mobility control. SP core floods were conducted using selected formulations in Indiana limestone cores. Coreflood experiments showed small increases in oil recovery over waterflood after the injection of the chemical formulation. Succesful polymer transport was observed in SP corefloods at high temperature.
Successful Adoption of New Technology: Implementation of a Global Drilling Bit Dysfunction and BHA Vibration Initiative
Authors: Willis John
Published: October 2018

Previously published technology that was not used in a company was implemented using a new approach based on marketing technology that resulted in widespread adoption and a lasting change. The drilling technology was available for years in SPE papers. Previous attempts to implement it failed to establish lasting application. The initiative took about two years and resulted in the use of the technology being well established. In addition to the process used to implement the initiative, the drilling technical process is also summarized.

The initiative drove implementation of the use mechanical specific energy (MSE) and other techniques to identify and minimize bit dysfunction and bit and bottomhole assembly vibrations. Full implementation of the techniques required drilling managers, superintendents, and engineers in the office, company drill site managers on rigs, and drilling contractor and service company personnel both on site and in the office all to understand the value of the technology, as well as know how to apply it.

The implementation process included an initial awareness phase of sharing successes by early adopters to create demand for the technology. Implementation included comprehensive training, management support, technical tools, and ongoing support.

The result of the initiative was a dramatic improvement in drilling performance. Significant increases in rates of penetration were achieved with virtually no added operational cost. Good results have been obtained in all business units, and the processes have evolved into routine practices.

The key conclusion is that proven marketing techniques can be adapted and applied to internal initiatives. The technology of marketing is effective and available, but adapting it to use internally is not trivial or obvious. On some previous initiatives, the approach was to deliver the technology, then create demand for it. The technique used this time was to create the demand first, then deliver the technology. This approach was successful in reducing opposition.

Early adopters must be identified and supported. Their initial successes are used to create demand for the technology and willingness to participate in training and learning. Training must be delivered to all of the people involved to enable application of the new process or technology.

Management support and technical support are both essential to get past difficulties. Patience and understanding are the best techniques to deal with resistance. Ultimately, successful results are the key to full adoption, but successful results cannot be achieved without the previous steps.

This case history includes both the principles and the application to a real case, with enough information on the drilling technology to understand the marketing process. The novel and additive information is how to adapt marketing technology for internal use, which is important for companies to adopt new technology faster.
A Diffusion-Corrected Sigma Algorithm for a Four-Detector Pulsed-Neutron Logging Tool
Authors: Schmid Gregory , Pemper Richard , Dolliver Darrell , Mekic Natasa , Musselman Jon
Published: October 2018

Sigma logging is a proven method for determining oil/water saturation behind casing. In this paper, we present a new, diffusion-corrected, sigma algorithm for a four-detector pulsed-neutron logging tool. Since the diffusion effect is inversely related to the distance between source and detector, there is an advantage in having multiple detectors at varying distances from the source. We will show how we use this advantage to design a diffusion-corrected sigma algorithm, and will verify the results using lab data, MCNP simulation, and field logs. Furthermore, we will discuss our use of a dual-exponential fit to cleanly separate the borehole decay from the formation decay. We will show that this approach works well, and can provide a certain advantage relative to the "moments method".
A Method for Calculating More Accurate Stratigraphic Positioning of Horizontal Wells Using Continuous Inclination and Azimuthal Gamma Ray Images Even While Sliding
Authors: Gutiérrez Carrilero Susana , Holmes Anne , Hinz David , Wang Jiaxin , Crawford Jeffrey , Stockhausen Ed , Wang Haijing
Published: October 2018

Geosteering long lateral wells in narrow target windows demands accurate stratigraphic positioning, true vertical depth (TVD) positioning, and apparent dip determinations. Using positive displacement motors with alternating slide and rotate drilling modes to control the well trajectory, along with standard 90-ft surveys and single-detector azimuthal gamma ray (GR) tools, have proven to be inadequate. To overcome these issues, a new method has been developed that combines continuous measurements and uses a four-detector azimuthal GR tool.

The bottomhole assembly (BHA) used here is equipped with two inclinometer packages and a four-detector azimuthal GR logging-while-drilling (LWD) tool. A high-resolution survey is calculated using a combination of the two continuous inclination survey data sets for the deeper portion of the well and the stationary survey data from the shallow (low inclination) portion of the well, which provides a more accurate well path that better reflects the TVD positioning of the wellbore. The four-detector azimuthal GR tool is used to generate high-quality wellbore images, both while sliding and rotating. This enables more accurate structural dip angles to be determined from the continuous GR images. It also leads to better stratigraphic and structural positioning of the wellbore and a better understanding of changes in stratigraphy across the length the lateral section. Combining more accurate surveys with complete GR images and more accurate dip picking enables a better determination of the stratigraphic position of the wellbore and its path through stratigraphic layers. The wellbore can be divided into various up- and down-drilled sections that can be compared side-by-side using true vertical thickness (TVT) methods to show lateral continuity of the beds.
Successful Replacement of Conventional Organophilic Clay with Novel Polymer as Viscosifier and Filtration Control Agent in Mineral-Oil-Based Drilling Fluids
Authors: Zhou Jing , Cortes Jairo , Nasr-El-Din Hisham
Published: October 2018

Oil-based drilling fluids (OBDF) can enhance wellbore stability in water-sensitive reservoirs and protect metal surfaces of drilling equipment to minimize corrosion due to H2S and CO2. Components of OBDF include oil as the continuous phase and water as the dispersed phase, in conjunction with viscosifiers, emulsifiers, filtration control agents, and weighting materials. Two of the most common types of continuous phases in oil-based drilling fluids are diesel and mineral oil. Mineral oil is less toxic than diesel, and oil retention properties of OBDF with mineral oil are less than OBDF with diesel. Organophilic clays are clay minerals that have been treated with oil-wetting agents, which will make the clay oil-dispersible. Organophilic clays mixed in OBDF do not exhibit same viscosity or suspension characteristics as in water-based drilling fluids, because electrical interaction between particles is minimal, making it difficult to build viscosity and gel strength in high pressure and high temperature (HP/HT) wellbore conditions. A new mineral-oil-based drilling fluids (MOBDF) proposed was obtained by the successful replacement of conventional organophilic clay with a novel polymer.

Conventional organophilic clay and novel polymer were aged at 150°F for 16 hours. To evaluate the alteration of the wettability caused by the MBDOF and its components, surface tension and contact-angle measurements were made in the laboratory. With similar weight proportions, the apparent and kinetic viscosities of organophilic clay and cross-linked polymer were also compared.

Rheological properties and filtration characteristics tests were conducted using a rotational viscometer and a HP/HT filter press, under three simulated wellbore conditions (140°F/ 300 psi, 190°F/300 psi, and 250°F/500 psi). Filter cake is formed due to positive pressure between OBDF and pore throats pressure. As a barrier between wellbore and formation, it can minimize solids and fluids invasion. Core flooding test was conducted to evaluate permeability of the filter cakes and CT scan was used to measure the density distribution of the filter cakes. Emulsion droplets formed by mixing MOBDF filtrate fluids with formation water were observed to analyze emulsion plugging damage.

Experimental results show that the novel polymer has a promising future of practical application, by providing thermal stability and stable rheological properties for MOBDF in HP/HT conditions. It also brings lower filtration volume, higher quality filter cake and slightly greater emulsion plugging damage to formations than organophilic clay-based drilling fluids.
Advanced Formation Evaluation to Optimize Shale Development in Permian Basin
Authors: Ingerman Vladimir
Published: October 2018

Permian Basin reserves exceed the reserves of the largest conventional field in the world, Ghawar, Saudi Arabia [1].

To develop this field many companies use ‘factory drilling’ or ‘geometrical approach’. This approach decreases the cost of drilling and make sense for source rocks because these are hydrocarbons saturated rocks or the rocks where hydrocarbons have been cooked. Geometrical approach would be ideal for homogeneous formations, but as it will be shown below shale place are very inhomogeneous vertically and laterally. While a drilling cost for a single well is reduced, this approach significantly increases the overall development costs and environmental impact because of drilling a big number of low producing wells.

We found the way to solve this problem developing a technology that uses standard open-hole log data to calculate Production Profile that shows predicted production along the entire well.
Optimizing Drilling Parameters Using a Random Forests ROP Model in the Permian Basin
Authors: Nasir Ehsaan , Rickabaugh Caleb
Published: October 2018

A random forests Rate Of Penetration (ROP) model, along with heat maps, was used to challenge and optimize the drilling parameters for new wells based on the surface drilling data acquired from previous wells. The goal was to analyze the data to observe surface drilling parameter trends aiding in increased bit life and reduced bit wear resulting in maximizing ROP and minimizing Mechanical Specific Energy (MSE).

The four key variables investigated were weight on bit (WOB), surface RPM, mud flowrate and the drilling formation. Surface drilling data for this study was utilized from wells, within a 20 mile radius, where the same bit and motor drilled the entire vertical interval to TD. Heat maps and ROP models (created using support vector regression, random forests and boosted trees) were employed for this purpose. Data was cleaned up using cutoffs (from the minimum and maximum values expected by the drilling engineer) and plotting data distributions. K-fold Cross validation was applied when generating the ROP models. The aim was to focus on the optimization of drilling parameters using surface data only, due to the lack of sub-surface data availability. Using the methodology developed, the drilling parameters could be optimized to extend bit life and reduce bit trips by maximizing ROP and minimizing MSE.

The random forests ROP model was found to be the best with a 12% mean absolute error. The error could have been reduced further by introducing additional variables into the model that capture the changes in formation mechanical properties, downhole parameters and vibrations. This paper only focuses on learnings from surface drilling data. After a certain threshold (which differed for the different formations encountered) an increase in WOB didn' t result in a corresponding increase in ROP. Moreover, most of the ROP gains were observed to be in the shallower formations drilled. For the deeper formations, it was more beneficial to reduce MSE as the ROP was relatively lower no matter what the parameters.

This study used random forests, support vector regression and boosted tree methods to generate ROP models instead of neural networks. Even though neural networks are the most extensive, random forests are generally faster and were the most accurate of the three aforementioned methods used. The less time and computational resources required when compared to neural networks made random forests an attractive option for such a study.
Augmenting Hybrid Physics-Based Multivariate Analysis with the Alternating Conditional Expectations Approach to Optimize Permian Basin Well Performance
Authors: Lolon Ely , Agarwal Karn , Mayerhofer Michael , Oduba Oladapo , Melcher Howard , Weijers Leen
Published: October 2018

The oil and gas industry has used multivariate analysis (MVA) to evaluate how geology, reservoir, and drilling/completion parameters (well characteristics) relate to well production. Although many techniques are used, multiple linear regression (MLR) has been especially popular due to its ease of use and the interpretability of its parameters. However, when the relationship between response and predictor variables is highly complex or nonlinear, this technique can yield erroneous and misleading results. Recent work showed the benefit of combining statistical MLR with fracture and numerical reservoir (physics-based) modeling, which yields a more physically realistic production response to suggested completion changes (Mayerhofer, 2017). However, this work is limited to using the nonlinear relationships between production outcomes and only a few independent variables (i.e., proppant/fluid volumes pumped and fracture spacing). For practicality, other important predictors are still assumed to be linearly correlated to the response variable (e.g., predicted cumulative oil).

In this paper, we describe the implementation of the Alternating Conditional Expectations (ACE) approach and the interpretation of its results, and we highlight the main advantages and limitations of the approach in MVA using a simulated dataset and field data from the Permian Basin. The ACE approach is a non-parametric regression method (i.e., no explicit assumption about the relationships between dependent or response and independent or predictor variables is required). It maximizes the linear correlation between the response and predictor variables in the transformed space (the optimal transformations are derived solely from the given data) resulting in higher R-squared (R2) and smaller Root-Mean-Square-Error (RMSE) values compared to those obtained from the MLR. Because a priori assumptions about the functional form for a transformation (e.g., linear, monotonic, periodic, and polynomial) do not have to be imposed, the ACE-guided transformation can give new insights into the relationship between the response and predictor variables.

We have successfully identified nonlinear relationships between well production and completion/reservoir properties for horizontal wells in the Permian Basin by means of ACE plots, and we have developed closed functional forms for these relationships. When integrated into the overall workflow of MVA, coupled with completion cost models, the ACE model could produce more realistic and accurate well performance predictions— using not only completion/reservoir parameters that are easily calibrated or "history-matched" as in the physics-based models, but also parameters that cannot be conveniently evaluated with the physics-based models.
Is There Anything Called Too Much Proppant?
Authors: Srinivasan Karthik , Ajisafe Foluke , Alimahomed Farhan , Panjaitan Maraden , Makarychev-Mikhailov Sergey , Mackay Bruce
Published: October 2018

Unconventional completions in North America have seen a paradigm shift in volumes of proppant pumped since 2014. There is a clear noticeable trend in both oil prices and proppant volumes – thanks to low product and service costs that accompanied the oil price crash in early 2015. As the industry continues to recover, operators are reevaluating completion designs to understand if these proppant volumes are beyond what is optimal. This paper analyzes trends in completion sizes and types across all major unconventional oil and gas plays in the US since 2011 and tracks their impact on well productivity.

Completion and production data since 2011 from more than 70,000 horizontal wells in seven major basins (Gulf Coast, Permian, Appalachian, Anadarko, Haynesville, Williston and Denver Julesburg basins) and 11 major oil/gas producing formations were analyzed to examine developments in proppant and fluid volumes. Average concentration of proppant per gallon of fluid pumped was used to understand transitional trends in fracturing fluid types with time. Production performance indicators such as First month, Best 3 or Best 12 months of oil and gas production were mapped against completion volumes to evaluate if there are added economic advantages to pumping larger designs.

In general, all major basins have seen progressive improvements in average well performance since 2011, with the Permian Basin showing the highest improvement, increasing from an average first-six-months oil production of 25,000 bbl in 2011 to 75,000 bbl in 2017. The Gulf Coast basin, where the Eagle Ford formation is located, has seen a 6-fold increase in proppant volumes pumped per foot of lateral since 2011 while the Permian and Appalachian basins hit peak proppant volumes in 2015 and 2016 respectively. In Permian and Eagleford wells, higher proppant volumes in general have resulted in better production up to a certain concentration. In Williston and Denver basins, most operators are moving away from gelled fluids, and reduced average proppant concentration per fluid volume pumped shows inclination toward hybrid or slickwater designs. While some of these observations are tied to reservoir quality, proppant volumes have begun to peak as operators have either reached an optimal point or are in the process of reducing volumes.

Demand for proppant is expected to nearly double by 2020. As oil prices continue to recover, well AFEs continue to increase, despite multiple efforts to improve capital efficiency. The need for enhanced fracture conductivity and extended half-lengths on EURs are been discussed by combining actual observed production data and sensitivities using calibrated production models. The industry is moving toward large-volume slickwater fracturing operations using smaller proppants, but he operating landscape is expected to see a correction when such designs become less economical.
Modeling of Matrix-Fracture Transfer with Non-Uniform Block Distributions in Unconventional Low-Permeability Fractured Reservoirs
Authors: Ding Didier-Yu
Published: October 2018

Unconventional tight-oil and shale-gas reservoirs are usually naturally fractured, and developing this kind of reservoirs requires stimulation via hydraulic fracturing to create conductive fluid flow paths via open fracture networks for practical exploitation. The presence of the multi-scale fracture network, including hydraulic fractures, stimulated and non-stimulated natural fractures, and micro-fractures, increases the complexity of the reservoir simulation. The matrix block sizes are not uniform, and they can vary in a very wide range, from several tens of centimeters to several tens of meters. In such a reservoir, the matrix provides most of the pore volume for storage, but makes few contributions to the global flow, while the fracture supplies the flow, however, with negligible contributions to reservoir porosity. The hydrocarbon is mainly produced from matrix-fracture interaction. So, it is essential to model accurately the matrix-fracture transfers with a reservoir simulator.

For the fluid flow simulation in tight-oil and shale-gas reservoirs, dual-porosity models are widely used. In a dual-porosity model, fractures are homogenized, and a shape factor, based on the homogenized matrix block size, is applied to model the matrix-fracture transfer. However, in real cases, the discrete fracture networks are very complex and non-uniformly distributed. One cannot determine an equivalent matrix block to compute the shape factor. So, a dual-porosity model is not accurate for the simulation of tight-oil and shale-gas reservoirs due to the presence of complex multi-scale fracture networks.

In this paper, we will study the MINC (Multiple Interacting Continua) method for the flow modeling in fractured reservoirs. MINC is usually considered as an improvement of the dual-porosity model. However, a standard MINC approach, using transmissibilities derived from the MINC proximity function, cannot always handle correctly the matrix-fracture transfers when the matrix block sizes are not uniformly distributed. To overcome this insufficiency, we present some new approaches for the MINC subdivision and the transmissibility computations. Several examples are presented to show that using the new approaches improves significantly the dual-porosity model and the standard MINC method for non-uniform block size distributions.
Boosting Oil Recovery in Naturally Fractured Shale Using CO2 Huff-n-Puff
Authors: Pankaj Piyush , Mukisa Herman , Solovyeva Irina , Xue Han
Published: October 2018

Although hydraulic fracturing in Liquid-Rich Unconventional Reservoirs (LUR) have become a norm, the recovery factor continues to be low. Use of Enhanced Oil Recovery (EOR) techniques in LUR have recently become more popular to improve the recovery. The objective of this study is to numerically investigate the advantages and disadvantages of the application of CO2 huff-n-puff technique in the LUR formations having complex fracture networks.

The study explores the fluid flow mechanisms for oil recovery in the naturally fractured reservoir. A calibrated 3D mechanical earth model with geomechanical and petrophysical property from the Eagle Ford was used for the study. Complex hydraulic fracture model was used to simulate the hydraulic fractures, proppant and fluid distribution around the wellbore. Numerical reservoir simulation on a Perpendicular Bi-section (PEBI) grid was used to capture the permeability, porosity and conductivity distribution due to the proppants in the hydraulic fractures. CO2 huff-n-puff technique using numerical reservoir simulation is used to determine the well performance and recovery factor arising from reservoir fluid viscosity reduction and gas expansion. Effect of fluid thermodynamics to recovery systems in the low permeability reservoir medium is fully captured in approach. Equation of state prepared for simulating the CO2 impact on the oil is prepared with correlating the collected down hole oil sample.

Numerical reservoir simulation study coupled with the complex fracture simulation model presents the insights of new means to improve RF in LUR through the injection of CO2. Such EOR method would be critical to increase the long term economic benefits. The study demonstrates that the infill well requirements can be mitigated if the EOR method of Huff-n-puff is utilized in cyclic modes over various time periods of production. Up to 9% extra RF was observed when CO2 Huff-n-puff technique was used as compared to production dependent only on hydraulic fracture stimulation. Parametric sensitivity on job sizes and start timing of EOR in a producing well is used to evaluate the RF. However, the hydraulic fracture geometry and the created footprint along with the time of injection has a larger effect in improving the EOR effectiveness.

The methodology provides the demonstration of simulating the EOR methods in unconventional reservoirs for economic assessment. The workflow demonstrates modeling CO2 flooding as an EOR technique on the full wellbore level with complex hydraulic fracture geometry. The approach demonstrated here can be applied to other basins in the unconventional formations to improve the recovery factor.
Importance of Accurate Reservoir Fluid Characterization in Unconventional Offshore Resources and How Asphaltene Behavior Impacts Reserve Prediction
Authors: Seibold Patricia , Krueckert Karsten Karl
Published: October 2018

Reservoir fluids are a complex hydrocarbon system that passes unique compositional stages when pressure and temperature change. Proper collection and accurate evaluation of a representative reservoir fluid sample during the exploration phase is one of the first crucial steps describing the chemical and physical nature of the hydrocarbon mixture. Understanding the importance of having a proper fluid characterization from the beginning of the development stage gets particularly essential in context of asphaltene precipitation and potential damage in unconventional reservoirs. Even in conventional reservoirs, formation damage caused by asphaltene deposition can have a severe impact on oil production and the prediction of remaining recoverable hydrocarbons in place. Multiple fraccing of unconventional tight oil reservoirs, conducted to produce economically despite low permeabilities, enhances the effect of uncertainty in reserve estimation. Precipitated asphaltenes potentially pjlug small pore throat channels in the near wellbore zone whereas high permeable fractures connect a wide area deep into the reservoir. Possibilities to maintain the reservoir pressure, e.g. water injection, are often limited due to the low permeability, consequently making it hardly manageable to stay above the asphaltene onset pressure in tight oil reservoirs.

Having a firm understanding of the reservoir fluid and the asphaltene properties helps to reduce unexpected occurrences during production and later field life as well as predicting remaining recoverable reserves in place.

This paper describes the fluid characterization of unconventional resources in a complex offshore environment and the effort undertaken to get a proper understanding about the hydrocarbon fluid phase. Challenging interpretations of conducted experiments about the asphaltene nature have been intensively studied to support forthcoming decisions in the field development process. Furthermore, the outcome of those analyses has led to a detailed investigation about the impact of asphaltene behavior in tight oil reservoir formation and the impact in prediction of remaining recoverable hydrocarbons.