bluuebunny/crossref_metadata_2025_split huggingface dataset:
Rapid Flood Operation Analysis and Optimization: A Case Study from the Midland Basin
Authors: Liu Guoxiang , Bruns Alex , Murrell Glen 
Published: April 2019

Abstract
The effectiveness of secondary and tertiary recovery projects depends heavily on the operator's understanding of the fluid flow characteristics within the reservoir. 3D geo-cellular models and finite element/difference-based simulators may be used to investigate reservoir dynamics, but the approach generally entails a computationally expensive and time-consuming workflow. This paper presents a workflow that integrates rapid analytical method and data-analytics technique to quickly analyze fluid flow and reservoir characteristics for producing near "real-time" results. This fast-track workflow guides reservoir operations including injection fluid allocation, well performance monitoring, surveillance, and optimization, and delivers solutions to the operator using a website application on a cloud-based environment. This web-based system employs a continuity governing equation (Capacitance Resistance Modelling, CRM) to analyze inter-well communication using only injection and production data. The analytic initially matches production history to determine a potential time response between injectors and producers, and simultaneously calculates the connectivity between each pair of wells. Based on the inter-well relationships described by the connectivity network, the workflow facilitates what-if scenarios. This workflow is suitable to study the impact of different injection plans, constraints, and events on production estimation, performance monitoring, anomaly alerts, flood breakthrough, injection fluid supply, and equipment constraints. The system also allows automatic injection re-design based on different number of injection wells to guide injection allocation and drainage volume management for flood optimization solutions. A field located in the Midland basin was analyzed to optimize flood recovery efficiency and apply surveillance assistance. The unit consists of 11 injectors and 22 producers. After optimization, a solution delivering a 30% incremental oil production over an 18-month period was derived. The analysis also predicted several instances of early water breakthrough and high water cut, and subsequent mitigation options. This system couples established waterflood analytics, CRM and modern data-analytics, with a web-based deliverable to provide operators with near "real-time" surveillance and operational optimizations.
Single Point High Pressure Gas Lift Replaces ESP in Permian Basin Pilot Test
Authors: Pronk Branden , Elmer William , Harms Larry , Nelle Will , Hacksma James 
Published: April 2019

Abstract
Long known for its tolerance of solids-laden fluid and wellbore deviation, gas lift is an increasingly popular artificial lift method for horizontal unconventional wells. A variation of gas lift known as Single Point High Pressure Gas Lift (SPHPGL), noted for the absence of gas lift valves, is now practical because of the availability of high discharge pressure compression equipment.
In SPE 187443 (Elmer 2017), the authors of this paper proffered that Annular SPHPGL could lift large liquid volumes. Further, this lift method was potentially a competitive alternative to failure prone Electric Submersible Pumps (ESPs) which are often used early in the life of horizontal wells to produce at high rates. The authors provided Nodal Systems Analysis to support this claim but lacked actual data from field testing. Finally, they appealed to industry to implement and perfect this "not new" but timely technology.
When the referenced paper was presented at the October 2017 SPE ATCE, high pressure compressors were not available from industry for lease. This situation changed in early 2018, with rental equipment becoming available in the Permian Basin. Subsequently, a Permian Basin operator (SM Energy) agreed to perform a pilot test in Howard County, Texas to test the conclusions listed in the paper, primarily that Annular SPHPGL could compete rate-wise with ESPs. Plans for a pilot test were made. Additionally, the production facility was modified to handle the possibility of higher flowrates than normally observed with ESPs, as well as increased slugging.
Injection down the tubing with returning flow up the tubing-casing annulus began in September 2018. Initial production rates were close to Nodal Systems Analysis predictions, and comparable with ESP flowrates. This proved that this technique could in fact compete rate-wise with ESPs.
For operators using liquids-rich produced gas for gas lift, the importance of maintaining gas temperatures elevated throughout the compression process is documented. Also, the positive results of the production facility modifications to handle higher flowrates and possible slugging are presented.
A Critical Review of Using High Viscosity Friction Reducers as Fracturing Fluids for Hydraulic Fracturing Applications
Authors: Ba Geri Mohammed , Imqam Abdulmohsin , Flori Ralph 
Published: April 2019

Abstract
The primary purpose of using traditional friction reducers in stimulation treatments is to overcome the tubular drag while pumping at high flow rates. Hydraulic fracturing is the main technology used to produce hydrocarbon from extremely low permeability rock. Even though slickwater (water fracturing with few chemical additives) used to be one of the most common fracturing fluids, several concerns are still associated with its use, including usage of freshwater, high-cost operation, and environmental issues. Therefore, current practice in hydraulic fracturing is to use alternative fluid systems that are cost effective and have less environmental impact, such as fluids which utilize high viscosity friction reducers (HVFRs), which typically are high molecular weight polyacrylamides. This paper carefully reviews and summarizes over 40 published papers, including experimental work, field case studies, and simulation work. This work summarizes the most recent improvements of using HVFR’s, including capability of carrying proppant, reducing water and chemical requirements, its compatibility with produced water, and environmental benefits in hydraulic fracturing treatments. A further goal is to gain insight into the effective design of HVFR based fluid systems.
The findings of this study are analyzed from over 26 field case studies of many unconventional reservoirs. In comparing to the traditional hydraulic fracture fluids system, the paper summaries many potential advantages offered by HVFR fluids, including: superior proppant transport capability, almost 100% retained conductivity, cost reduction, minimizing chemicals usage by 50%, less operating equipment on location, reducing water consumption by 30%, and fewer environmental concerns. The study also reported that the common HVFR concentration used was 4gpt. HVFRs were used in the field at temperature ranges from 120°F to 340°F. Finally, this work addresses up-to-date challenges and emphasizes necessities for using high viscosity friction reducers as alternative fracture fluids.
Data-Driven Analysis of Natural Gas EOR in Unconventional Shale Oils
Authors: Temizel Cenk , Balaji Karthik , Canbaz Celal Hakan , Palabiyik Yildiray , Moreno Raul , Rabiei Minou , Zhou Zifu , Ranjith Rahul 
Published: April 2019

Abstract
Due to complex characteristics of shale reservoirs, data-driven techniques offer fast and practical solutions in optimization and better management of shale assets. Developments in data-driven techniques enable robust analysis of not only the primary depletion mechanisms, but also the enhanced oil recovery in unconventionals such as natural gas injection. This study provides a comprehensive background on application of data-driven methods in the O&G industry, the process, methodology and learnings along with examples of data-driven analysis of natural gas injection in shale oil reservoirs through the use of publicly-available data.
Data is obtained and organized. Patterns in production data are analyzed using data-driven methods to understand key parameters in the recovery process as well as the optimum operational strategies to improve recovery. The complete process is illustrated step-by-step for clarity and to serve as a practical guide for readers. This study also provides information on what other alternative physics-based evaluation methods will be able to offer in the current conditions of data availability and the understanding of physics of recovery in shale oil assets together with the comparison of outcomes of those methods with respect to the data-driven methods. Thereby, a thorough comparison of physics-based and data-driven methods, their advantages, drawbacks and challenges are provided.
It has been observed that data organization and filtering take significant time before application of the actual data-driven method, yet data-driven methods serve as a practical solution in fields that are mature enough to bear data for analysis as long as the methodology is carefully applied. The advantages, challenges and associated risks of using data-driven methods are also included. The results of data-driven methods illustrate the advantages and disadvantages of the methods and a guideline for when to use what kind of strategy and evaluation in an asset.
A comprehensive understanding of the interactions between key components of the formation and the way various elements of an EOR process impact these interactions, is of paramount importance. Among the few existing studies on the use of data-driven method for natural gas injection in shale oil, a comparative approach including the physics-based methods is included but they lack the interrelationship between physics-based and data-driven methods as a complementary and a competitor within the era of rise of unconventionals. This study closes the gap and serves as an up-to-date reference for industry professionals.
Quantifying a New Horizontal Well Gas Anchor Performance
Authors: Karmon Isaac , Panacharoensawad Ekarit , Watson Marshall 
Published: April 2019

Abstract
The separation of gas from gas-liquid mixture in horizontal wells has become a growing concern in the oil and gas industry. The produced free gas reduces the efficiency of rod pump systems, minimizes oil production and can lead to the failure of the rod pump system due to gas locking phenomena. The impact of two-phase flow on the new horizontal well gas anchor’s performance was investigated experimentally. Each experiment was conducted in a transparent horizontal well flow loop by using water and air as the test fluids. Experiments with and without the new gas anchor in the flow loop cases were studied. The new tool has two mechanisms to prevent gas phase from entering the tubing. The first mechanism is the breakage of the mixture’s wave by the bull plug of the tool. The second mechanism is the separation of small gas bubbles due to the flow through the tortuous path inside the tool. This experimental program quantifies the tool performance regarding the first working mechanism only. The bubble separation via the tortuous path mechanism was not investigated.
The results showed that both with and without tool cases can separate 90 – 100% gas from the mixture, if the inlet of tubing or the tool was fully submerged under liquid phase of the mixture at all time. This condition was achieved under stratified flow where the horizontal part of the well was toe flat or toe-up (0°, +1°, and +2°). The wave breakage mechanism by the bull plug of the tool was confirmed visually. This breakage mechanism established the advantage of using the new gas anchor over no-tool condition.
Numerical Study on Casing Integrity During Hydraulic Fracturing Shale Formation
Authors: Wu Xiaye , Han Lihong , Yang Shangyu , Yin Fei , Teodoriu Catalin , Wu Xingru 
Published: April 2019

Abstract
Due to the layered texture and sedimentation environment, shale formations usually characterized as high heterogeneity and anisotropy in in-situ stresses. During the hydraulic fracturing process, fracturing fluid is injected at a pressure above the formation pressure. This injection process changes the local in-situ stresses in a quick and significant manner while generating fracture systems. In the regions of existing geo-features such as natural fractures and faults, local stress changes could lead to the activation of formation movement, which in return impacts the casing going through the locale. Casing deformations during hydraulic fracturing have been observed in Southwest China Sichuan basin, and it have impeded completion operations in certain regions. In order to ensure further exploring, we analyszed this phenomenon and propose practical solutions for fault reactivation prevention.
To study the mechanism of local slippage and the impact on casing integrity, we set up a 2D finite element model with considerations of in-situ stresses acquired from fields, natural fracture orientation from available seismic data, and we simulated water injection process in order to quantify potential slippage and displacement. The finite element model features an integration of casing, cementing, and formation under the hydraulic fracturing conditions. For particular parameters such as permeability and leak-off coefficeint, we conducted sensitivity studies to quantify their impacts on displacement amount.
The theoretical geomechanics studies indicate water induced slippage existence in shale due to its fracture reactivation. Using the finite element model, this paper interpreted and quantified the impact of fracturing fluid injection on casing from strike-slip fault regiems. Simulation results revealed that water injection into natural fractured shale formation can induce finite displacement characterized as fault slippage along discontinues surfaces. This study could help engineers to have a better prediction as how hydraulic fracture intereact with subsurface structures and potential risks that comes along with it. This type of casing damage can be reduced by improving well trajectory design, completion operation, and higher strength level of casing-cement system.
The findings from this study not only can be applied to naturally fractured formations, but also to other pre-existing geo-features such as discountinues surfaces. It also provides fundamental basis for more practical solution to find the measures and overcome the casing deformation problems in hydraulic fracturing.
Prevent Fouling and Corrosion During Mill-Out Operations: Case Studies
Authors: Galindo Tanhee 
Published: April 2019

Abstract
Case studies of mill-out operations in the Permian Basin which evaluate chemical programs and processes used. Results show how existing processes and chemicals used or lack thereof, can affect equipment and undo the preventative chemical treatments used during the hydraulic fracturing process.
The study looks at field water testing performed during various mill-out operations and considered workover rig vs coiled tubing, equipment set up, water & chemicals used, and operational challenges. Water analyses were completed on the injection water and returns at various intervals of the mill-out. Effectiveness of chemical treatment was also monitored when biocide was used.
Field case studies of horizontal wells for two operators in the Permian Basin are presented. Wells were milled-out utilizing workover rigs or coiled tubing units. Testing results show the impact of equipment setup and operations process on the water quality and efficiency of the chemicals used. Water fouling was prevalent in all cases, with coiled tubing jobs showing the highest degree of water contamination and chemical inefficiency. Changes in the water treatment program during operations showed significant improvement and sustainable results. Potential corrosion of the work string due to water fouling and water composition were also observed. The effects of changes to chemical dosages were also monitored. This was important because it identified operational improvements that can reduce equipment replacement costs, reduce chemical overuse and help protect wells from fouling due to high bacteria.
These case study provides a comprehensive review of mill-out operations, which provides guidelines for improving chemical efficiency and potential of extending life of the work string.
Methods and Apparatus for Artificial Lift of Water-in-Oil Emulsions
Authors: Gomez Sergio , Al Munif Eiman , Fahes Mashhad 
Published: April 2019

Abstract
Understanding the behavior of water-in-crude-oil emulsions is necessary to determine its effect on oil and gas production. The presence of emulsions in any part of the production system could cause many problems such as large pressure drop in pipelines due to its high viscosity. Electrical submersible pumps (ESPs) and gas lift are commonly used separately in lifting crude oil from wells. However, the use of downhole equipment and instruments such as ESPs that cause mixing can result in the formation of an emulsion with a high viscosity. The pressure required to lift emulsions is greater than the pressure required to lift non-emulsified liquids. Lifting an emulsion decreases the pressure drawdown capabilities, lowers production rate, increases the load on the equipment, shortens its life expectancy and can result in permanent equipment damage. Methods and apparatus which reduce the load on the pump, therefore, are desirable. The present paper is directed to understand the behavior of water-in-oil emulsions in artificial lift systems, mainly through gas lift.
Two stable water-in-oil synthetic emulsions were created in the laboratory and their rheology and stability characteristics were measured. One contained crude oil and the other, mineral oil. The second stage included measuring the effect of gas lift exposure on the emulsion behavior and characteristics. The results of the present work indicate that water-in-oil emulsions can be destabilized, and their viscosities lowered under gas exposure. The effect of gas injection on the emulsion was linked to the initial conditions of the emulsion as well as the gas type, injection rate and exposure time.
The present study is directed to methods and systems for combining both ESPs and gas lift for the purpose of improving and simplifying the lift of water-in-oil emulsions from oil wells. The novel methods and apparatus are based on the discovery that by adding gas above the ESPs in the wellbore, the viscosity of an oil-in-water emulsion is actually reduced, thus making it easier to lift oil from the well and extending the life of the ESP. Therefore, in addition to the normal benefits of gas in aiding the lift of liquids, if the gas lift valve is installed at a calculated distance above the pump location, the emulsion viscosity can be reduced. This reduces the load on the ESP.
Evaluation of Small-Scale Gas-to-Liquid Economic Feasibility to Mitigate North Dakota Flaring Issue
Authors: da Silva Sequeira Pascoela , Ghanbarnezhad Moghanloo Rouzbeh 
Published: April 2019

Abstract
The booming of shale gas production has affected the natural gas price in the United States (U.S). Natural gas price has plummeted due to the excessive capacity. On the other hand, the import of crude oil and its production of diesel, gasoline, and others are increasing. The problem lies in finding a practical, economical and efficient way of making natural gas marketable. A potential solution is Small-scale Gas-to-Liquids plants. Small-scale GTL can fulfill some of the petroleum products demand such as Gasoline, Ultra-low-sulfur diesel, and jet-fuel. Small-scale GTL plants especially can benefit countries where the gas production is higher than gas demand, yet these countries depend on imported oil.
A Monte Carlo simulation approach is used to conduct sensitivity analysis on various parameters such as the feedstock/natural gas price, plant capacity, plant efficiency, capital expenditure (CAPEX), operational expenditure (OPEX), and products selling prices. The range for natural gas prices and gasoline prices are obtained from average historical data in the United States for the past five (10) years where the shale gas production is booming. The CAPEX is attained from previous GTL project plants before using the Power-Sizing model and literature. The annual OPEX is the percentage fraction of the CAPEX. The plant capacity was chosen based on the diseconomy factor estimated from previous GTL projects. Even with the premium quality of GTL products, the selling price for the products is equal to regular crude oil products.
Economic metrics such as Net Present Value (NPV), Internal Rate of Return (IRR), Cost-to-Profit (C/P) ratio and Payback Period were used to assess the success of GTL technology at each given business case. Results showed that NPV, IRR, C/P ratio and payback period are most affected by CAPEX, products selling price, OPEX, and capacity of the plant, in respected order. Based on these case scenarios and parameters, sensitivity analysis is conducted using Monte Carlo's simulation of 10,000 iterations the results for NPV, IRR, C/P ratio and payback period showed that the GTL project is profitable. The NPVs for the GTL plant in this study are positive for all case scenarios.
It is expected that the outcome of this research would guide shale gas producers and private investors when considering GTL investment to monetize their assets in the United States and beyond.
Haynesville Shale: Predicting Long-Term Production and Residual Analysis to Identify Well Intereference and Frac Hits
Authors: Gupta Ishank , Rai Chandra , Devegowda Deepak , Sondergeld Carl 
Published: April 2019

Abstract
This study analyzes the production data from 2,755 horizontal wells in the Haynesville shale. Correlations were generated to predict 4,5,6, and 7-year cumulative productions from initial 6,12 and 24-months production data. These correlations can help in field development planning and economic analysis. The residuals (Predicted – Actual Cumulative Production) from these correlations were also analyzed and this technique can be used to identify wells affected by interference, refracturing, frac-hits, etc.
The cumulative production estimates from the developed correlations were also compared with the corresponding estimates from the DCA equations (seven different DCA methods used). The accuracy of prediction based on correlations developed in this study is at par with the various standard DCA methods published and used in the industry. The correlations are much faster to use and easier to implement for a large number of wells.
Another objective of the paper was to develop P10, P50 and P90 type curves for the Haynesville shale using the available production data. A subset of the total wells i.e. 150 wells evenly distributed throughout the study area, were used for predicting type curves. These type curves were generated and compared using different Decline Curve Analysis (DCA) models. The different DCA methods predicted an uncertainty of 5 to 27 % for the P10, P50 and P90 production profiles.