bluuebunny/crossref_metadata_2025 huggingface dataset:
Collaborative Real-Time Analysis to Reduce Non-Productive Time
Authors: Guidry Garrett , Spezia Kyle , Salmon Graeme
Published: October 2018

Operators often use real-time operation centers (RTOC) as a funnel point for data streams transmitted from multiple rigs during the well construction process. A RTOC is typically staffed by subject matter experts (SMEs), with the primary goals of interpreting real-time wellbore conditions and relaying actionable recommendations to help reduce nonproductive time (NPT) and well control incidents.

Automation is a strong industry trend. Autonomous systems are being developed to flag potential NPT events before they occur; however, these systems are not yet widely used. In the absence of these systems, workflows among complementary disciplines have been developed to identify potential NPT events in large data streams transmitted to a RTOC. This paper presents example scenarios from deepwater prospects with potential actionable recommendations.

Robust data streams transmitted to a RTOC can be received by the overlapping disciplines of hydraulics optimization, drilling optimization, and geomechanics. Staff from each discipline filter through the raw data to capture incoming information relevant to their respective output analysis. A key goal of each discipline is to mitigate the risk of NPT through real-time identification of warning trends observed during deepwater drilling in narrow pressure window situations. The multidisciplinary overlapping efforts produce a process that is much more effective than is possible with each discipline operating independently. Because real-time geomechanics seeks to update the bounding conditions of the downhole pressure operating windows, collaborative workflows are structured around validation and calibration of the real-time geomechanical model.

Collaborative workflows are presented for specific operations during the well construction process in which NPT events are likely to occur, such as tripping out of the hole and drilling. In the examples, real-time calculated equivalent circulating density (ECD) models, hole cleaning parameters, swab pressure models, and torque/drag plots provide input to the real-time geomechanical model. Outputs of this analysis are actionable recommendations, such as an extended flow check, check trip, or mud weight increase. The workflows were developed based on lessons learned from information in a central database and the resulting best practices from multiple deepwater wells.

Decision makers are provided with data-supported recommendations at crucial junctures; these recommendations typically involve costly rig time. The trade-off between increased rig time and benefits gained from the recommendation is difficult to quantify. The workflows derived from a library of NPT events address the perception of wasted rig time and provide context to real-time interpretations. Combined plots supporting the recommendation provide confidence for the driller that the increased rig time is time justified.
Mechanistic Modeling of Electrical Submersible Pump ESP Boosting Pressure Under Gassy Flow Conditions and Experimental Validation
Authors: Zhu Jianjun , Wang Zhihua , Zhu Haiwen , Cuamatzi-Melendez Ruben , Martinez-Farfan Jose Alberto , Jiecheng Zhang , Zhang Hong-Quan
Published: October 2018

As an artificial lift method for high-flow-rate oil production, electrical submersible pumps’ (ESP) performance surfers from gas entrainment, a frequently encountered phenomenon in ESPs. When it occurs, ESPs can experience moderate or severe head degradation accompanied with production rate reduction, gas locking and flow instabilities. For the design and operation of an ESP-based production system, the accurate model is needed to predict ESP boosting pressure under gassy flow conditions. In this paper, a simplified mechanistic model is proposed to model gas-liquid flow inside a rotating ESP. The model not only maps flow patterns in ESPs but also captures the multiphase flow characteristics in terms of in-situ gas void fraction, boosting pressure, bubble size, etc.

The experimental facility for testing ESP gas-liquid performance comprises of a 3″ stainless steel fully closed liquid flow loop and ½″ semi-open gas flow loop. A radial-type ESP with 14 stages, assembled in series, was horizontally mounted on the testing rig. Pressure ports were drilled at each stage to measure stage-by-stage pressure increment. The mixture of gas and liquid is separated in a horizontal separator, where excessive gas was vented and the liquid continues circulation. Experimental data were acquired with two types of tests (mapping tests and surging tests) to completely evaluate the pump behaviors at different operational conditions. The water/gas flow rates, ESP rotational speeds, intake pressure etc. were controlled in the experiments.

The new model starts form from Euler equations, and introduces a best-match flowrate at which the flow direction at ESP impeller outlet matches the designed flow direction. The mismatch of velocity triangle in a rotating impeller results from the varying liquid flow rates. Losses due to flow direction change, friction, and leakage etc., were incorporated in the model. Based on the force balance on a stable gas bubble in a centrifugal flow field, the in-situ gas void fraction inside a rotating ESP impeller can be estimated, from which the gas-liquid mixture density is calculated. The predicted ESP boosting pressures match the corresponding experimental measurements with acceptable accuracy.
An Efficient Probabilistic Assisted History Matching Tool Using Gaussian Processes Proxy Models: Application to Coalbed Methane Reservoir
Authors: Rana Sachin , Ertekin Turgay , King Gregory R.
Published: October 2018

Currently used assisted history matching algorithms such as differential evolution, particle swarm optimization etc. usually requires a large number of numerical simulation runs in order to converge to acceptable solutions. If each numerical simulation takes a long time to complete, these algorithms become inefficient. In this research, a new assisted history matching tool is presented that can provide multiple solutions of history matching in much less number of numerical simulations. The proposed tool uses Gaussian process based proxy models to provide fast approximate forward solutions which are used in Bayesian optimization to find history match solutions in an iterative manner. The uncertainty in history match solutions is quantified via MCMC sampling on trained forward GP model. In order to check for independence and convergence of the collected MCMC samples, auto-correlation plots and Geweke z-score diagnostic tests are also performed. The converged MCMC samples are then used to quantify uncertainty in EUR of gas reserves via a forecasting GP model. The proposed methodology is successfully applied to a synthetic heterogeneous coalbed methane reservoir. The code and data for this case study is also available online for future studies. The results show that history matching can be performed in approximately four times less number of numerical simulation runs as compared to state of the art differential evolution algorithm. Besides, the P50 estimate of EUR is shown to be in close agreement with truth values for the presented case study.
Deriving Reservoir Net Pay Cutoffs from Mercury Injection Tests and Routine Core Analysis
Authors: Shi Xinlei , Lv Hongzhi , Li Xingli , Cui YunJiang , Li Ting
Published: October 2018

The net pay cutoffs are the critical parameters in calculating the total pay thickness and estimating hydrocarbon reserves. To determine these parameters, the industry has been largely relying on drill stem tests (DST) or downhole fluid samplings, which provide information on the productive capacity of different pay intervals. However, due to the high operational cost, these measurements are typically quite scarce, particularly in offshore oilfields. In complicated reservoirs where hydrocarbon viscosity shows vertical variation, the net pay cutoffs change as well and hence even more measurements are required to accurately characterize the changing cutoffs.

In this paper, we propose a novel workflow to derive the porosity and permeability net pay cutoffs by integrating core Mercury Injection for Capillary Pressure (MICP) test and core porosity and permeability, therefore reducing the need for costly DST and sampling. Our core dataset consists of 1024 rock samples, among which 529 have MICP test data. These samples come from 14 oilfields in Bohai Bay where the operator has some local knowledge of the porosity and permeability cutoffs, as well as the oil viscosity. In general, the porosity and permeability cutoffs discovered through testing have a poor correlation with oil viscosity.

Using our core dataset, we built a localized Winland equation relating the apex pore throat aperture (Rapex) to core porosity and permeability. With this equation, we translated porosity and permeability cutoffs into Rapex cutoff. Our study shows that Rapex cutoff has a much better correlation with viscosity than porosity cutoff and oil density. Based on this finding, we developed the following workflow to accurately predict porosity and permeability net pay cutoffs from oil viscosity using Rapex as a guide: For all rock samples, graphically find the apex aperture radii on the corresponding MICP curves.Using regression, find customized Winland equation relating Rapex to core porosity and permeability.For oilfields where the porosity and permeability cutoffs are well defined, calculate Rapex cutoff corresponding to porosity and permeability cutoffs using the equation in step 2. Plot oil viscosity against Rapex cutoffs in a chart and fit an exponential function to the sample points.For new oilfields with known oil viscosity but unknown net pay cutoffs, we enter the oil viscosity into the chart in the previous step and read off the Rapex cutoff value from the regression line.Draw the porosity and permeability values corresponding to the Rapex cutoff in a poroperm plot using the equation in step 2, and draw the core porosity and permeability points from the field under study as overlay. The porosity and permeability net pay cutoffs can be found at the intersection of the core points and the Rapex line.

The porosity and permeability cutoffs found using Rapex cutoff are highly consistent with those found by actual DST or samplings.
Upconversion Nanoparticles as Tracers for Production and Well Monitoring
Authors: Murugesan Sankaran , Agrawal Devesh , Suresh Radhika , Khabashesku Valery , Darugar Qusai
Published: October 2018

Luminescent upconversion nanoparticles are used as alternate fluorescence tracers to overcome the interference of organic molecules in the analysis of flowback waters. Upconversion nanoparticles use low-energy excitation at approximately 980 nm with high-energy emissions in the region of 200 to 950 nm. Emission properties of the nanoparticles are tuned by selective doping, and their dispersiblity in water and oil are altered through appropriate functionalization. The flow experiments used stable crude oil emulsions in API brine with the mixture of two different emission upconversion tracer nanoparticles. Data from these experiments suggest that the nanoparticle tracers can flow through the porous media and distinguish between each other, even in the presence of organics in an emulsion. This capability can open new avenues in in-situ reservoir communication and understanding.
Big Data Analytics for Seismic Fracture Identification, Using Amplitude-Based Statistics
Authors: Udegbe Egbadon , Morgan Eugene , Srinivasan Sanjay
Published: October 2018

Present day innovations in seismic acquisition tools and techniques have enabled the acquisition of detailed seismic datasets, which in many cases are extremely large (on the order of terabytes to petabytes). However, data analysis tools for extracting information on critical subsurface features such as fractures are still evolving. Traditional methods rely on time-consuming iterative workflows, which involve computing seismic attributes, de-noising and expert interpretation. Additionally, with the increasingly widespread acquisition of time-lapse seismic surveys (4D), there is a heightened demand for reliable automated workflows to assist feature interpretation from seismic data.

We present a novel data-driven tool for fast fracture identification in BIG post-stack seismic datasets, motivated by techniques developed for real-time face detection. The proposed algorithm computes spatiotemporal amplitude statistics using Haar-like bases, in order to characterize the seismic amplitude properties that correspond to fracture occurrence in a unit window or voxel. Under this approach, the amplitude data is decomposed into a collection of simple-to-calculate "mini-attributes", which carry information on the amplitude gradient and curvature characteristics at varying locations and scales. These features then serve as inputs to a cascade of boosted classification tree models, which select and combine the most discriminative features to develop a probabilistic binary classification model. This overall approach helps to eliminate the computationally-intensive and subjective use of ad-hoc seismic attributes in existing approaches.

We first demonstrate the viability of the proposed methodology for identifying discrete macro-fractures in a 2D synthetic seismic dataset. Next, we validate the approach using 3D post-stack seismic data from the Niobrara Shale interval within the Teapot Dome field. We show the applicability of the proposed framework for identifying sub-seismic fractures, by considering the amplitude profile adjacent to interpreted fullbore microimage (FMI) well log data. The upscaled spatial distribution of the predicted fractures shows agreement with existing geological studies and align with interpreted large-scale faults within the interval of interest.
Capping Stack Technology Comes of Age
Authors: Cuthbert Andrew
Published: October 2018

While several years have passed since the 2010 Gulf of Mexico (GOM) source control incident that caused a six-month drilling moratorium, the industry likely believes it is fully prepared to prevent or mitigate the effects of a similar incident in a timely manner. However, installing a source control device on a blowing well is a technically complex exercise, one that has never been performed; while performing such an operation, one should consider challenges posed by metocean conditions, coupled multiphase hydrodynamics, and multibody interactions that complicate the deployment and docking of a capping stack onto a subsea wellhead.

The latest gate-valve technology intended to close against flow presents a more compact option for rapid capping than unwieldy ram-based systems. The speed of deployment of the lighter capping stack is attributed to the availability of suitable aircraft, lifting equipment at the airport or dockside, and an ample supply of suitable deployment vessels. The underlying logistical issues that prevent rapid responses to subsea incidents have not, for the most part, been addressed until now. A development differentia in capping-stack technology has been necessary to exact the speed of response that the industry calls for and to meet the expectations of stakeholders and the general public. Fortunately, the industry now has access to technology that can be deployed to a source control incident in any global location in a matter of days.

Sophisticated, high-fidelity simulation, hitherto unavailable, incorporates metocean sea state and uses coupled multiphase hydrodynamics and multibody interaction effects of vessel motion, suspension system dynamics, and the hydrodynamics of the capping system within the unstable blowout forces to create an accurate analysis that addresses plume and landing-force analysis at the wellhead. Coupled with the tools to accurately simulate the effects of the force dynamics from surface to wellhead to complete the entire process, the advances accompany the new capping design and enhance the ability to determine landing capability, heralding further advancement in source control technology and techniques.
Case Studies in Deriving Holistic Insights from an Automated Drilling Optimization Platform
Authors: Vempati Chaitanya , Dolezal Tisha
Published: October 2018

The last decade has seen a tremendous increase in the use of oilfield data to understand problems of well construction, evaluate drilling performance and derive guidance on future drilling. Despite the tremendous increase in investment and application of various data mining techniques, the outcomes in the well construction domain have been subpar when compared to that of other industries. Yet analysis of drilling data has resulted in useful predictions on the small scale–comparing a few wells where the huge number of variables that influence drilling (formation, rig, bottomhole assemblies [BHA], etc.) have little fluctuation. However, making actionable predictions on a much greater scale, and in the presence of significant variability, is substantially more challenging. The authors introduce a new platform for automated drilling analysis and optimization. The system starts with an enhanced in-bit measurement device that enables an improved view of downhole conditions at a higher density. This data is then tied to surface measurements through robust data validation and streamlined capture of variables. Finally, the platform ties state-of-the-art, physics-based models, which capture the physics of drilling from cutter-rock interface, to power delivery from the rig through the BHA to quantify the influence of each variable. This coupling of physics-based modeling and models based on drilling data is used to deliver key holistic insights–not just on speed of drilling, but also balance it against borehole quality, efficiency and health of the tools. Results of this new optimization platform, which was tested in the SCOOP and STACK plays of Central Oklahoma, are presented in this paper. The platform shows the power of combining physics and measured data to detect hidden insights, derive actions and enhance drilling performance.
A New Transient Model to Simulate and Optimize Liquid Unloading with Coiled Tubing Conveyed Gas Lift
Authors: Han Guoqing , Ma Gaoqiang , Zheng Jian , Gao Yue , Zhang He , Ling Kegang
Published: October 2018

Nowadays, unloading gas wells with coiled tubing is a common application to the field. However, it still lacks of adequate understanding of dynamic behavior of the unloading process. This paper investigates the process of liquid unloading by gas lift with coiled tubing under transient condition. This unloading process can be divided into three stages: liquid rising in tubing, liquid slug production, and liquid production by entrainment. In each stage, the mass and linear momentum conversation equations are applied as governing equations. The components of each stage includes coiled tubing, coiled tubing-tubing annulus, liquid slug, gas bubble, and liquid film. Empirical correlations have been used including surface gas injection choke, check valve, friction factor, the relationship between the gas bubble and the liquid slug velocity, inflow performance relationship, and blackoil fluid properties. From the above, the dynamic model coupling real-time change of inflow performance relationship. Using the LU factorization and Euler's method to solve the proposed dynamic model in time domain. Among all these variables, the most important ones include gas injection rates, pressures at various locations, length of the liquid slug and gas bubble, and various velocities. By the simulation efforts, the mechanism of liquid unloading process is revealed.

Gas lift is commonly constrainted by gas availability. This is pioneer study on liquid unloading with coiled tubing is critical in design phase to optimize the usage of injected gas as well as choose appropriate pump and cost-saving for electricity expense.
Microemulsion Effects on Oil Recovery from Kerogen Using Molecular Dynamics Simulation
Authors: Bui Khoa , Akkutlu I. Yucel , Zelenev Andrei S. , Hill W. A. , Griman Christian , Boudreaux Trudy C. , Silas James A.
Published: October 2018

Source rocks contain significant volumes of hydrocarbon fluids trapped in kerogen, however their effective recovery is challenged due to amplified fluid-wall interactions and the nanopore confinement impact on fluid composition. Enhanced oil production can be achieved by modifying the existing molecular forces in kerogen pore-network by using custom-designed targeted chemistry technologies. Our objective is to show how the transport of hydrocarbons in kerogen and its recovery can be altered with the delivery of microemulsion nanodroplets into the pore network. This is done by using computational chemistry and molecular dynamics (MD) simulations.

Molecular dynamics simulation is used to generate a 3D model replica of a Type II kerogen representative of source rocks located in Delaware and Midland basins in the United States. Oil phase saturated kerogen is modeled as consisting of nine different types of molecules: dimethyl naphthalene, toluene, tetradecane, decane, octane, butane, propane, ethane and methane. The delivered microemulsion is an aqueous dispersion of solvent-swollen surfactant micelles. The solvent and nonionic surfactant present in the microemulsion are modeled as d-limonene and dodecanol heptaethyl ether (C12E7), respectively. Molecular dynamics simulation experiments include two steps: (i) the injection of microemulsion treatment fluid into the oil-saturated kerogen pore-network, and (ii) transient flow-back of the oil-chemical mixture in the pore network. The utilized 3D kerogen models were developed based on a representative oil sample composition (H, C, O, S, N) from the region. Simulation results show that microemulsions can affect the reservoir via two different mechanisms. During the injection, microemulsion nanodroplets that enter the nano-capillaries of pore network disperse in the liquid present in the pore space under the influence of pore walls. The solvent dissolves in the oil phase and alters the physical and transport properties of the phase, while the surfactant molecules modify the wettability of the solid kerogen surfaces. The recovery effectiveness of heavier oil fractions is improved compared to the recovery effectiveness achieved with surfactant micelles without the solubilized solvent.

New 3D kerogen models are presented using atomistic modeling and molecular simulations. These models possess important chemical and physical characteristics of the organic matter of the source rock. Molecular dynamic experiments indicate that solubilized solvent and surfactant are delivered as part of a microemulsion droplet and are expected to aid the mobilization of oil present within kerogen.
Far-Field Diversion Technology to Prevent Fracture Hits in Tightly Spaced Horizontal Wells
Authors: Vidma Konstantin , Abivin Patrice , Dunaeva Anna , Panga Mohan , Nikolaev Max , Usoltsev Dmitriy , Mayo JT
Published: October 2018

More than 60% of US land wells drilled in 2017 are infill wells. Fracturing in such wells is likely to cause fracture hits on adjacent wells, which may have a negative impact on the infill and nearby existing well production. A new technology has been developed to control the geometry of the fracture, which reduces significantly the fracture hit rate and increases production in the child (infill) and parent wells.

Traditional methods for controlling the geometry of hydraulic fractures include adjusting pad and proppant volumes and fluid viscosity. The proposed technology uses an alternative approach, delivering a multimodal particulate diversion mix with the proppant. The job is designed so that the diversion mix bridges and accumulates at the fracture tip, thus confining the fracture perimeter and controlling fracture length growth.

The proposed technology has been field tested in 11 wells (219 stages) in the Eagle Ford shale. The results showed high efficiency of fracture hit prevention (84% of stages free of fracture hits) and increased production in the child and parent wells. The technology showed high operational reliability, (no premature screenouts) and was proven to be cost effective and robust. Laboratory experiments were conducted to tailor the permeability of the diversion blend. Because the diversion blend contains very small particulates, a wellsite delivery method was developed to prepare the blend and deliver it safely. Guidelines for the diverting pill pumping schedule were developed to optimize fracture hit prevention.

The developed technology demonstrates that the complicated process of fracture growth geometry correction can be performed with intelligent engineering design including a far-field diversion pill.
Application of Hollow Fiber Membrane Contacting System for CO2/CH4 Separation
Authors: Ghobadi Jalil , Ramirez David , Khoramfar Shooka , Jerman Robert , Crane Michele , Oladosu Olufemi
Published: October 2018

Carbon dioxide separation using membrane based contacting system is a reliable alternative to traditional gas absorbent techniques such as wet scrubbers. The main objective of this research was to design, develop and implement a hollow fiber membrane based contactor system to absorb and separate CO2 from CH4 in a simulated flare gas stream.

Gas-liquid contacting system was constructed using microporous polytetrafluoroethylene (PTFE) hollow fibers as a highly hydrophobic membrane. The module used for the experimental studies has 51 mm diameter and 200 mm effective length. The membrane module had the packing density of 60 % and the PTFE hollow fiber being employed in this module had the mean pore size of 0.48 μm. Experiments conducted in a laboratory-scale plant fed with a simulated flare gas mixture containing 2.5 % of CO2 balanced with CH4 which could produce varying concentrations of inlet gas using mass flow controller.

CO2 separation experimentation studies were performed and effect of operational variables on separation efficiency of the system has been studied. In order to optimize the gas separation performance of the membrane module, effects of gas and liquid flow rates, absorbent-phase concentration, and nature of scrubbing liquid were examined. The absorption efficiency of deionized-water and aqueous solutions of sodium hydroxide (NaOH) and diethanolamine (DEA) as the physical and chemical absorbents has been compared. Results indicated that increasing the flow rate and concentration of scrubbing liquid can enhance the separation efficiency; however, increasing the flow rates of the gas-phase has a negative impact on the CO2 absorption performance of the system.

The traditional CO2 separation process suffers from many limitations, such as high capital and operational costs, and potential of equipment corrosion. Membrane processes offer attractive opportunities for gas treatment applications including removal of CO2, H2S, and SO2 from flare gas mixtures. This technology offers a variety of practical benefits including low energy and operation costs and at the same time it can help to mitigate the adverse health effects associated with burning the waste gases.
Implementing Blockchain Technology in Oil and Gas Industry: A Review
Authors: Lakhanpal Vikrant , Samuel Robello
Published: October 2018

The oil and Gas industry has recently transformed itself into a data-intensive industry – artificial intelligence, machine learning and internet of things. With such growth and expansion, distributed ledger technology, commonly known as blockchain, can carry the industry's transformation forward. This technology can help the industry to overcome various challenges such as price volatility, supply chain, accounting, data management and security. It can also help in streamlining various engineering and technical decisions.

Technologically, the oil and gas industry has been very innovative – 3-D seismic, hydraulic fracturing, geosteering, imaging beneath salt, etc. However, the administrative and managerial functions are still done in a somewhat traditional way. The Blockchain technology can help the industry become more efficient by streamlining these traditional methodologies.

This paper presents the four major areas where the blockchain technology can help the industry overcome various day to day challenges – (1) Supply Chain and Trading, (2) Regulatory, (3) Database Management and (4) Cyber Security.

Like any new technology, the blockchain technology might not get a full embrace at the beginning, but the idea is to present a qualitative study about its benefits. The industry currently has little or no knowledge about this technology, which is expected to bring transparency, security and convenience in one place. The objective of this paper is to help the industry peers understand the idea behind this technology and how it can transform the way the industry currently operates. It provides a frame of reference for the industry to realize the potential of this technology and assess its benefits.
Far-Field Diversion System Designed for Slickwater Fracturing
Authors: Vigderman Leonid , Bogdan Andrey , Shen Lingjuan , Heller David , Yeung Tony , Fu Diankui
Published: October 2018

Fracture geometry control and increased fracture complexity have been recognized to be critical factors in optimizing unconventional well completion design as well as preventing detrimental frac hits. A major challenge of far-field diversion in slickwater fracturing is ensuring transport of material to the fracture tip or secondary fracture in a low-viscosity fluid. This paper will present a novel far-field diverter system for fracturing with low-viscosity fluids to address these challenges composed of an engineered mixture of unique ultra-lightweight proppant and degradable material. Not only can the system effectively divert fracturing to control fracture geometry and enforce complexity, but will also maintain fracture conductivity.

Several types of tests were performed to determine the effectiveness and optimize the design of the far-field diverter system. First, a series of slot plugging tests were carried out to optimize diversion performance of the system by blocking fluid flow through targeted fracture widths while maintaining flow through the larger portions of a fracture. Next, the diverter was pumped through a flow apparatus to demonstrate its far-field transportability in low-viscosity fluids. Finally, conductivity of the diverter system after degradation was tested.

The new far-field diverter system was designed to create a permeability barrier at the fracture tip to contain fracture length growth as well as to be used in the middle of a stage to control growth of secondary/tertiary fractures to allow redistribution of fracturing fluid within the rock to further increase complexity. Lab tests demonstrated that by controlling the particle size of the engineered proppant and diverter mixture, the diverter system can be tailored to plug different fracture widths. Significantly, flow tests using a low-viscosity, slickwater fluid demonstrated the excellent transport properties and limited settling rate of the diverter. Finally, conductivity tests showed that by using an engineered mixture of non-degradable, ultra-lightweight proppant and degradable material, conductivity in the fracture is maintained after particle degradation, which is critical when applied in the middle of a stage to increase fracture complexity.

To the authors’ knowledge, this is the first published paper of a far-field diverter that is optimized for slickwater fracturing for both fracture geometry and complexity control. The new diverter technology overcomes the significant limitations of other available systems such as fracture closure, inadequate transport to the far field, or the requirement to use high viscosity fluids.
Improved Efficiency of a Nitrate Reducing Bacteria/Nitrate Treatment by the Incorporation of a Sulfate Analog
Authors: Gawas Kiran , Safarin Dana , Riley Howard , Ogle James
Published: October 2018

Hydraulic fracturing in the Marcellus Shale play has moved to produced water only scenarios because of prohibitive water disposal costs. Well completion under produced water only conditions increases the demand on chemical additive performance. In addition, water reuse selects deleterious microorganisms through natural selection, which may increase the likelihood of formation souring. Conventional biocides are typically used to mitigate these risks, but to some extent, they present health, safety, and environmental (HSE) concerns. In addition, several conventional biocides have side reactions with sulfide, notably tetrakis(hydroxymethyl)phosphonium sulfate (THPS) and 2,2-dibromo-3-nitrilopropionamide (DBNPA). This paper describes an improved method for the effective control of deleterious microorganisms without the use of conventional biocides.

An environmentally friendly system that includes nitrate-reducing bacteria (NRB) coupled with nitrate co-introduction was previously shown to mitigate souring as effectively as a biocide alternative for more than 1,000 assets. The NRB inhibit growth of the deleterious sulfate-reducing bacteria (SRB) primarily by competing for the available carbon source if the source is limited. This paper describes an improved NRB/nitrate system that incorporates a sulfate analog, which presumably inhibits dissimilatory sulfate reduction and enhances mitigation. Laboratory experiments were performed to measure the amount of hydrogen sulfide (H2S) produced in field brine samples inoculated with SRB. The improved NRB/nitrate system was shown to inhibit the production of H2S under worst-case scenarios in laboratory competitive exclusion experiments.

Results for the new treatment at four trial wells are presented. Sulfate-reducing bacteria populations, acid-reducing bacteria populations, and a gaseous H2S concentration were monitored over three months and were found to satisfy the operator's set key performance indicators. Overall, the amount of chemical required for treatment was reduced for this improved system, which substantially reduced the operator costs to treat the wells.

The combination of chemistries with mutually exclusive cellular targets highlights the value of synergistic effects, specifically reducing system cost to treat while retaining low aquatic toxicity, as compared to traditional biocides used in the oilfield.
Understanding Development Drivers in Horizontal Wellbores in the Midland Basin
Authors: Cherian Bilu , Shoemaker Michael , Nwoko Stephanie , Narasimhan Santhosh , Olaoye Olubiyi , Iqbal Javed , Peacock Joshua , Becher John , Ferguson Brittney , Zakhour Nancy
Published: October 2018

The Permian Basin in North American has been the driving force behind global energy growth, resulting from the exploitation of unconventional resources. The combination of high quality stacked resources, horizontal drilling, completion tools, and hydraulic fracturing innovations has accelerated the learning curve in this basin over the past few years: which was the impetus of this study.

This paper utilizes an integrated model approach to understand reservoir performance on a pad with four wells completed across multiple horizons in the Midland Basin. Rich multi-domain data sets were utilized that included seismic, wireline triple-combo, compressional and shear log suites, core (rock mechanics testing, geochemical analysis (XRF and XRD) and routine core analysis), completion data (fracture treatments with pre-and post-job shut-in pressures), and production data including 1,500 days of production history with bottom-hole pressure gauge data. 3-D surface seismic, high tier logs, and core data were used initially to create a facies model. Properties were distributed into a geo-model using the existing vertical well-control and seismic as constraints. A sector model was then built that enabled modeling of 4 development wells that consisted of parent well, followed by 3 child-wells. The history matching of fracture treatments and production data with bottom-hole pressure data resulted in significant understanding of key parameters driving subsurface performance.

A workflow, representing the seamless integration of said models, is presented that enables an improved understanding of what impact sequence and timing of operations has on the subsurface contact area as well as the implied change in well performance if an optimal strategy is executed. Geomechanical facies that drive vertical connectivity and fracture geometry, as well as reservoir parameters that impact fracture contact with the reservoir, were identified.
Drilling Extended Laterals in the Marcellus Shale
Authors: Doak Joshua , Kravits Matthew , Spartz Michael , Quinn Pat
Published: October 2018

A drilling team has focused on increasing lateral lengths in the Marcellus Shale over the past couple of years. The team reevaluated prior drilling processes that had been in place for 7,000’ to 9,000’ laterals in order to determine what operational practices would need to be revised in order to drill and case laterals in excess of 18,000’. We focused on rig upgrades, directional tools, drilling fluids, casing floatation and other best practices. We even implemented field trials on various lateral lengths in efforts to evaluate extended lateral practices prior to drilling the first 18,000’ lateral.

Over the twelve month period of revised processes and upgrades, we drilled thirty-four horizontal wells each exceeding 12,000’ in lateral length – this included two wells in excess of 17,850’ with one exceeding 18,000', which represented the first drilled Marcellus lateral to exceed that length. This paper covers the details of those processes and upgrades that led to dozens of successful Marcellus horizontal wells with extended lateral lengths.
Impacts of Field Depletion on Future Infill Drilling Plans in the Marcellus Shale
Authors: Shahkarami Alireza , Wang Guochang , Rohland Zachary
Published: October 2018

The development of shale assets has reached a point where operators face the challenge of infill drilling. The scope of this project is to investigate the impact of neighboring well pads on the performance of a newly developed well/pad. This paper highlights the differences in production performance of "old" pads versus "new" well and analyzes how the depletion history of the existing pads affects the performance of new well.

The study area covers two pads: Pad A and Pad B which have 10 and 12 wells respectively; these wells have been producing since 2016 from the dry gas region of Marcellus Shale in southwestern Pennsylvania. Pad A and Pad B are more than 9000 ft apart, and the region between these two pads has potential for future development. For this project, a 3-D reservoir simulation model that includes both pads was built and calibrated to match past performance of Pad A and Pad B. The calibrated simulation model then was utilized for developing new wells. The reservoir simulation model was used to perform a sensitivity analysis on reservoir characteristics and the impact of Pad A and Pad B's depletion history on the performance of new well(s). The workflow involves optimizing the well spacing of proposed well(s) with/without considering the depletion history.

Usually, with the very low permeability of shale reservoirs, the depletion history of neighboring wells is expected to affect the performance of newly developed wells. The new wells are considered as a different well pad, and their stimulated reservoir volume does not overlap with the Pad A and Pad B. However, the region average reservoir pressure is reduced due to the Pad A and Pad B production history. In most of shale reservoir numeral simulation studies, the reservoir is considered virgin. The average reservoir pressure potentially impacts the well spacing optimization workflow as well as the designing of an effective well completion job. In this study we compare two scenarios. One scenario considers the depletion history of neighboring well pads and the other one does not. The net present value optimization was done with and without considering the impact of depletion history.

This project studies the effects of neighboring well pads on production performance of newly developed pad. Compared to the interaction of parent/child well in a single well pad, multi-pad studies are rare primarily because of the high computational cost associated with a multi-pad numerical simulation analysis.
An Integrated Approach to Optimize Perforation Cluster Parameters for Horizontal Wells in Tight Oil Reservoirs
Authors: Lu Yu , Li Haitao , Lu Cong , Liu Chang , Chen Zhangxin
Published: October 2018

Perforation parameters have a great influence on the performance of the multi-stage fracturing horizontal wells in tight oil reservoirs. Optimizing perforation cluster parameters is able to solve many detrimental issues, including many null perforation clusters without the produced oil, the unevenly distributed output in each stage along horizontal wells, and no complex fracture network always created near the fractured wellbore. To achieve the better performance of the volume fracturing, a practical integrated approach is proposed to optimize perforation cluster parameters. First, based on the good logging data, we establish an evaluation method for the fracability and reservoir properties to select the perforation interval. Second, a mathematical model based on the stress shadow and hydraulic fracture propagation are proposed to optimize the cluster spacing and cluster parameters within each cluster in the same stage, and the un-uniform cluster spacing and perforation number in each cluster are studied. Finally, a case well is successfully conducted with the proposed approach in the tight oil reservoir. Results show that i) the lateral with higher fracability index and property index can be treated as perforation intervals; ii) the un-uniform perforation cluster spacing and the uneven perforation number can obtain a more uniform fracture propagation morphology. The approach can better prevent the generation of ineffective perforation clusters and obtain more complex fracture networks and a better SRV. This also guides to design completion strategy and improves the economic benefits.
A Systematic Approach for Reducing Scaling Effects and Enhancing Production in Depleted Carbonate Reservoirs in the Permian Basin
Authors: Boulis Tasos , Millsaps Logan , Troutman Tony , Polk Dustin
Published: October 2018

Scaling precipitation in the form of calcium or iron sulfate (CaSO4 – FeSO4) appears to be a common problem in most of the wells completed in the Yeso formation in the Permian Basin. Accumulation of these forms of scale in the perforations and the downhole equipment can create severe production losses and therefore they require constant, some times costly, treatments. Additionally, their presence in the wellbore hinders the efficiency of the acidizing procedures, performed by the operators to further increase the productivity of their wells.

The objective of this paper is to present an innovative workflow, which significantly reduces the scaling effects and allows the acidizing of these carbonate reservoirs to be more efficient. Results are avialble for more than 20 wells, from Occidental Petroleum’s assets in the North New Mexico region. Details regarding the evolution of the procedure, the types and amounts of the chemicals are extensively discussed in this paper.

The procedure starts with the candidate well selection, which preferably are located in the highest OOIP areas to maximize the efficiency. The second step involves the water sampling and analysis to determine the types of scaling and consequently the required chemical treatment. The innovation in this step has to do with the time that converters are left in the wellbore and the extra chemicals that have been added compared to the previous procedures. The last step involves the deployment of the acid downhole, where three different methodologies have been tested and evaluated based on their efficiency and well returns.

The proposed approach has been successfully applied to more than 20 wells and the results are encouraging showing an average incremental oil production of ~600% while the execution cost remains very low.
Optimized Rock Fluid Interaction and Stimulation Intensity Enhancement Improves Well Performance: A Marcellus Case Study
Authors: Budney Tim , Jose Chirinos , Jacot Henry , Svarczkopf Tim
Published: October 2018

Large volume slick-water stimulations have become the de facto standard for completion strategy in the Upper Devonian, Marcellus, and Utica/Point Pleasant. Current completion optimization work has focused on optimizing stage spacing, sand loading, and injection rate which have shown increases in well productivity. One commonly overlooked variable in the design equation is stimulation fluid chemistry and rock/fluid interaction. Friction reducers, the primary additive of a slickwater system, have become a commodity with many service companies providing similar systems. Premium slickwater systems in the Marcellus are generally characterized by the ability to tolerate high percentages of produced water.

We have developed an alternative approach to the design of stimulation fluid chemistry. This approach consists of creating a comprehensive laboratory workflow justification for multiple fluid combinations with consideration for specific thermal maturity windows. The laboratory workflow includes proprietary rock/ fluid interaction tests that insure formation compatibility, lever imbibition/displacement production mechanisms, insure compatibility of fluid components inclusive of available water sources, and insure optimization of the fluid based on stimulation intensity (Budney 2017) objectives. After extensive testing, a new stimulation fluid chemistry has been developed that offers several advantages verified by laboratory testing. The new stimulation fluid chemistry consists of a multifunctional additive with the following characteristics: salt tolerant, viscosifying, formation stabilizing, wettability enhancing friction reducer technology paired with a compatible scale inhibitor and biocide. This new stimulation fluid chemistry was field tested against an incumbent fluid chemistry provided by the stimulation service company. Well production data from the first multiple well experiment demonstrated the new stimulation fluid chemistry resulted in significantly improved well performance. A second multi-well experiment in a different area was conducted and proved the well performance improvement associated with the new stimulation fluid chemistry was repeatable. Economic analyses on wells from both field experiments demonstrate an excellent return on investment with the new stimulation fluid chemistry.

This study highlights the importance of justifying stimulation fluid chemistry utilizing a laboratory workflow. The laboratory workflow incorporates rock/fluid interaction testing to maximize the imbibition/displacement production mechanism. The laboratory workflow must also prove that the stimulation fluid chemistry satisfies the stimulation intensity objectives of high rate, high sand concentration, and reduced fluid volumes while enabling reliable field execution.