Paper Presenters Price
(20) ADVANCED SUCKER ROD COUPLING MATERIAL OPTIMIZES EFFICIENCY AND PRODUCTIVITY ON ROD LIFT WELLS

Tubing leaks have historically accounted for nearly half of the failures in the Hess Bakken wells. The root cause of these leaks is coupling on tubing wear; the non-metallic guides wear out, which results in spray metal couplings contacting the production tubing. To address this problem, the company installed ToughMet® 3 TS95 sucker rod couplings in over 650 wells, reducing the failure rate in the field. Data analytics was used to analyze the MTBF history over the last four years.

   

Several operators are running entire sucker rod strings with the ToughMet couplings to determine if friction can be reduced and production improved. Wells with full strings of ToughMet couplings could see increased fluid production, increased pump fillage, higher fluid loads, and lower gearbox loads. Results of these pilots will be discussed.  

 


Carolyn Curran, Diane Nielsen and Richard Cash, Materion Corporation
Seth Silverman, Hess Corporation
 

$7.50
2018020 ADVANCED SUCKER ROD COUPLING MATERIAL OPTIMIZES EFFICIENCY AND PRODUCTIVITY ON ROD LIFT WELLS
Price
$7.50
(23) A COMPARISON OF API ROD PUMPS, MODIFIED API PUMPS, AND SPECIALTY PUMPS

This paper will discuss the two API pump designations the rod pump and the tubing pump. The rod pump is occasionally referred to as an insert pump and has three variations; stationary barrel top anchor, stationary barrel bottom anchor, and traveling barrel bottom anchor. Available modifications that are not covered under API but are commonly used to improve run time or efficiency will be discussed. Several special design pumps will be described along with their advantages. A reader will be able to recognize the standard API pump designs, API designs with modifications, and specialty pumps.  In the end, the reader will be able to evaluate which application of each pump design should be used.


Rodney Sands, Harbison-Fischer

$7.50
2018023 A COMPARISON OF API ROD PUMPS, MODIFIED API PUMPS, AND SPECIALTY PUMPS
Price
$7.50
(25) AN ARTIFICIAL LIFT STRATEGY FOR UNCONVENTIONAL WELLS IN THE PERMIAN BASIN

There are a large number of unconventional wells coming on line every month in the Permian Basin.  Most of these wells will have high bottom-hole pressures and initially flow on their own. However, after the initial flow back phase, pressures and rates decline and the well will begin to liquid load. At this point some type of artificial lift choice needs to be considered. This paper will lay out an artificial lift strategy for many of these wells that will transition from completion to depletion through various artificial lift options as a well’s production and pressures decline. The production phases reviewed will be: Completion, Flowing, Intermitting, Gas Lift, Plunger Assisted Gas Lift, Plunger Lift, Multistage Plunger Lift and finally Gas Assisted Plunger Lift


Mike Swihart, Plunger Lift Companies, Inc.

$7.50
2018025 AN ARTIFICIAL LIFT STRATEGY FOR UNCONVENTIONAL WELLS IN THE PERMIAN BASIN
Price
$7.50
(29) OILFIELD TECHNOLOGY CENTER - TEXAS TECH UNIVERSITY

Located on 10 acres of land near the intersection of East Loop 289 and Fourth Street in Lubbock, the Bob L. Herd Department of Petroleum Engineering Oilfield Technology Center (OTC) is designed to serve as a research and teaching facility to give petroleum engineering students a hands-on experience in the design and operation of typical oilfield equipment. This paper will discuss the capabilities of the facility as well as plans for future growth.


Denny Bullard and Marshall Watson
Texas Tech University
 

$7.50
2018029 OILFIELD TECHNOLOGY CENTER - TEXAS TECH UNIVERSITY
Price
$7.50
(31) GENERATION AND APPLICATION OPTIONS FOR CHLORINE DIOXIDE AND ITS VARIOUS APPLICATIONS IN THE OILFIELD

Chlorine dioxide has a wide variety of applications in the oilfield, including fracturing, water flood, salt water disposal wells and producing well stimulation.  It is uniquely suited to deal with the core problems of microbiological fouling, H2S, iron sulfide and oil/water emulsions.  The unique attributes of this oxidizing chemical mean that it will not react with hydrocarbons and most amines (unlike other oxidizers), and thus is effectively targeted on the problems most commonly encountered.  



There are multiple ways to generate chlorine dioxide, both from the standpoint of the precursor chemicals used, and the equipment used for the generation.  This paper will address these methods of generation and application of chlorine dioxide, along with the advantages and disadvantages of each for specific types of application.

 


Garry D Laxton, International Dioxide

$7.50
2018031 GENERATION AND APPLICATION OPTIONS FOR CHLORINE DIOXIDE AND ITS VARIOUS APPLICATIONS IN THE OILFIELD
Price
$7.50
(32) SLURRY HYDROGEN SULFIDE REMOVAL PROCESS

A new sulfur removal process utilizing traditional iron oxide in a very unique way.  The process produces a highly effective technology to completely remove H2S and eliminate acid gas disposal, liquid chemical management and other environmental challenges.



The process is based on a proprietary granular BrimsorbTM F. The granules are mixed with water to form a slurry that comes into contact with H2S-laden gas.  The process is simple to operate, has a small footprint, and has VERY low capital and operating costs. The regenerable nature of the adsorbent reduce operating costs, but the non-hazardous elemental sulfur and iron oxide byproduct can easily be disposed of thereby minimizing any environmental impact.

Compared to the traditional liquid processes and Sulfur Recovery Units:



1. Adsorbent Capacity: the adsorbent is a proprietary amorphous hydroxyl iron oxide, which is regenerable thereby having high sulfur removal capacity.

2. Environmentally friendly: the slurry can be regenerated which reduces the wastewater discharge, and eliminates the secondary pollution caused by by-products in competitive processes.

3. Wide range of process applications: this process is also suitable for removing H2S from biogas, coke oven gas, associated gas, natural gas, gaseous and liquid streams from petrochemical industry. 

Presentation will explain a new environmentally sound option for treating high H2S natural gas that can reduce capital and operating expense.

 


Maureen Solomon and Chien-Min Lee
GTC Vorro
 

$7.50
2018032 SLURRY HYDROGEN SULFIDE REMOVAL PROCESS
Price
$7.50
(33) DESIGN CONSIDERATIONS FOR A SUSTAINABLE WATER MANAGEMENT SYSTEM, BASIC ENERGY SERVICES

The presentation opens by highlighting the Industry’s responsibility for environmentally safe water disposal, then discusses the pros and cons of Vendor Owned / Managed versus Company Owned / Operated water systems. Design considerations for the holistic water management system are as follows:

 

•         System Capacity and Layout : Evaluate not only current needs, but future needs. Design for the “worst” case scenario, by building the system above current volumes and determine what expansion will be required for the future drilling program.

•         Pipeline Material and Sizing : Factors to consider are cost to buy and install, operating pressures, surface injection pressures, water corrosiveness, and environmental concerns.

•         Pit Sizing and Construction : Define goals / needs with respect to water quality and total volumes. 

•         Pump Selection & Other  Equipment : Determine which type and size of pump is needed for the specific application, and where to install ESD valves, BPV’s and check valves.

•         Settling Time & Tank Storage Volumes : Design for projected field volumes and the potential injection downtime, water quality and oil-carryover in produced water.

•         Water Compatibility, Scale, & Chemicals : Analyze and understand water scaling tendencies  and/or compatibilities of the produced water, fresh water, and vendor’s fracking chemicals.

 


Ken Fairchild, Basic Energy Services

$7.50
2018033 DESIGN CONSIDERATIONS FOR A SUSTAINABLE WATER MANAGEMENT SYSTEM, BASIC ENERGY SERVICES
Price
$7.50
(34) PRODUCED WATER RECLAMATION IN THE PERMIAN BASIN USING CHLORINE DIOXIDE

High disposal costs and a limited availability of freshwater have led many industry players in the Permian Basin to reclaim produced water and use it in subsequent well fracturing. This reclamation process typically involves pumping produced water from numerous production batteries to a central location where it is placed in storage in large surface impoundments until such time that it is needed in fracturing operations.  Unfortunately, a natural process referred to in the oil and gas industry as “souring” can occur within these impoundments during the time period when the produced water is being stored.  Souring can occur quickly and render produced water completely unsuitable for subsequent use in fracturing without extensive and costly in situ chemical and/or physical treatment, thereby negating all incentives the industry has for recycling this water. Produced water also typically contains a high concentration of dissolved ferrous iron (Fe2+), which has the potential to cause significant operational issues downhole if used in fracturing without some form of pretreatment.



This paper describes in detail how constituents present in produced water cause surface impoundment souring to occur, and demonstrates, with supporting field application data, how chlorine dioxide (ClO2) can facilitate economical reclamation by simultaneously treating both problematic aspects of produced water prior to its subsequent storage in surface impoundments. First, ClO2 readily oxidizes undesirable soluble ferrous iron present in produced water to the insoluble ferric form (Fe3+).  Second, ClO2 helps break the natural “chain of causation” that leads to impoundment souring by destroying bacterial emulsions, which in turn allows entrained oil to effectively separate from the water, and suspended solids, including precipitated ferric iron, to drop out via gravitational settling and/or mechanical filtration. Finally, because ClO2 is a highly penetrating gas, it quickly pervades any volume of produced water requiring treatment, thereby allowing for process adaptation to virtually unlimited flowrates.

 


Darrell Dechant, Scott Breeding and Taylor Reynolds
Aegis Chemical Solutions

$7.50
2018034 PRODUCED WATER RECLAMATION IN THE PERMIAN BASIN USING CHLORINE DIOXIDE
Price
$7.50
(35) COLD FINGER TESTING – THE GOOD, THE BAD AND THE UGLY

The Cold Finger Test is the primary test presently used by Chemical Vendors to select Paraffin Inhibitors to prevent paraffin deposition in producing gas and oil wells, gathering systems, treating facilities and pipelines. If a good Test procedure is used to erase the thermal history of 

the crude sample to be used and it reproduces the system Temperatures in the area to be treated an effective chemical will be chosen for that system’s paraffin problem.  Unfortunately, the economic conditions that have befallen the Industry in the past few years have caused both vendors and oil companies to look for short cuts to allow for more to be done with less. Cold Finger Tests are being done with less oil, larger temperature differentials between the oil temperature and the probe temperature and shorter test run times. The use of these short cuts makes more chemicals look good on the test, giving great % inhibition results that many times are not representative how the chemical will preform in the system. This paper will discuss good test procedures, bad tests procedures and how oil companies need to determine if the results they are getting make sense and have a good chance of solving their paraffin problems.

 


Kenneth Barker, Ken Barker Paraffin and Asphaltene Training

$7.50
2018035 COLD FINGER TESTING – THE GOOD, THE BAD AND THE UGLY
Price
$7.50
(36) A GUIDE TO OIL FIELD TESTING

Oilfield operations are like an intricate time piece, all gears must be moving in perfect synchronization in order for everything to run smooth and for the hands to keep moving.  But when a wrench gets thrown into the gears, how do you know where it came from.   When the flow stops there are a range of issues that can be the culprit such as bacteria, scale, paraffin/asphaltenes, and corrosion.  Identifying the cause of the issues can sometimes be problematic but this paper will cover the various methods of determining where the wrench landed in the gears and give a brief introduction to the different testing methods for the oilfield.


Larry Hines, BHGE

$7.50
2018036 A GUIDE TO OIL FIELD TESTING
Price
$7.50
(37) MITIGATING PARAFFIN BUILDUP IN UPTON COUNTY, TEXAS - HARNESSING INNOVATIVE TECHNOLOGY TO PREVENT PARAFFIN BUILDUP FROM CAUSING AND CONTRIBUTING TO WELL FAILURES

Paraffin mitigation has been the subject of many case studies involving various chemical blends, treatment frequencies and in some cases down hole tools. All with varying degrees of success, most leave the operator left managing the issue rather than mitigating it. Struggling to find an effective solution for wells in Upton county, Diamondback set out to find a solution beyond the typical conventions. Establishing a systematic approach, Diamondback found a solution that mitigates paraffin formation, prolongs well run times and ultimately reduces operating expenses for Diamondback wells.


Matt Berkebile, Diamondback Energy
Amber Krummel, Revelant
 

$7.50
2018037 MITIGATING PARAFFIN BUILDUP IN UPTON COUNTY, TEXAS - HARNESSING INNOVATIVE TECHNOLOGY TO PREVENT PARAFFIN BUILDUP FROM CAUSING AND CONTRIBUTING TO WELL FAILURES
Price
$7.50
(38) DYNAMIC CONTACT ANGLE MEASUREMENTS

Contact angles between fluids are important in capillary tube measurements in oil industry.  Contact angle measurements are important to determine both surface and interfacial tension between solids and various fluids. In the oil industry, it is very important to have a water-wet condition on the rock face in order to extract oil. If the rock wettability is oil wet, the oil company will need to make the right decision to improve oil recovery by injection of CO2 (Carbon Dioxide), surfactant, and/or mixed alkaline and surfactant to change the rock wettability. Interfacial or surface tension exists when two phases are present. These phases can be gas/oil, oil/water, or gas/water. The aim of this project is to determine the contact angle of different fluids when they interact with each other and the solid surface. This work was focused on the determination of the wettability (water wet or oil wet), and analyzed the effect of different brine concentrations on wettability and contact angle measurements using the Dynamic Contact Angle Analyzer (DCA 315). In this work results, fluid with the lowest contact angle produces the most favorable conditions for oil extraction. In addition, the surfactant is desirable as it maintains a high surface tension even when mixed with different brine concentrations.


Mahmoud  Elsarafi, Adanna Okoye, Chiedz Tokonyai and Jomarie Leblanc
Midwestern State University
 

$7.50
2018038 DYNAMIC CONTACT ANGLE MEASUREMENTS
Price
$7.50
(39) FORECASTING THE RESERVOIR DATA OF OILFIELD IN LIBYA BY USING DECLINE CURVE ANALYSIS

Decline Curves Analysis commonly ordinarily applied to evaluate the original hydrocarbon in place, hydrocarbon reserves, and forecasting future production performance. The Decline Curves Analysis development was presented by Johnson and Bollens in (1928) and later on (1945) which is called "loss-ratio". Many discussions of the mathematical relationship between the past time, production rate, and the cumulative production depend on the decline rate. Decline Curve Analysis is a technique which might be stratified for a single well or whole reservoir by either production engineer or reservoir engineer. In oil industry, remaining reserves are the substantial target. The objective of this study is to determine and clear estimation of a reservoir performance in Libyan Oilfields by using Decline Curves Analysis and estimate the reservoir life. Also, in this work we simulate the production operation data to find out the better matching of forecasting results and the economic impact of the selected reservoir. This research is an attempt to determine one of Libyan reservoir performance and determine which one of the three classifications of the Decline Curves are Exponential, Hyperbolic, and/or Harmonic by using one of the most widespread important reliable methods to estimate the depletion of reservoir pressure with the consideration of the method limitations, the changes in the facilities downstream, and hydrocarbons production rate.


Mahmoud Elsharafi, Mohamed Hussen Masuad, and Faisal Bergigh
Midwestern State University
 

$7.50
2018039 FORECASTING THE RESERVOIR DATA OF OILFIELD IN LIBYA BY USING DECLINE CURVE ANALYSIS
Price
$7.50
(41) MINIMIZE RISK AND INCREASE RELIABILITY OF BALANCED CEMENT PLUGS WITH TAILPIPE DISCONNECT TOOL

The development of horizontal drilling combined with hydraulic fracturing has allowed operators to develop unconventional plays once considered uneconomical. As operators move toward drilling more complex sections in these plays, proper placement of a competent cement plug on the first attempt becomes increasingly challenging. The use of a bottom hole kickoff assembly (BHKA) minimizes risk and increases reliability for all cement plug operations; plugback, kickoff and/or abandonment. This tool disconnects from sacrificial tubing run at the end of the workstring, eliminating the need of pulling the workstring through the cement plug.



An operator in the Delaware Basin planned to drill vertical pilot holes in two wells to perform evaluation of potential target zones. The operator sought to plugback the pilot hole and kickoff to drill the horizontal section into the target zone. This paper describes the use of the BHKA tool to set 1200 ft plugbacks in these wells.

 


Olvin A. Hernández, Jacob Laufer, Matthew Martin and Mickie Hamilton
Halliburton
 

$7.50
2018041 MINIMIZE RISK AND INCREASE RELIABILITY OF BALANCED CEMENT PLUGS WITH TAILPIPE DISCONNECT TOOL
Price
$7.50
(42) USING ENGINEERED DIVERSION STRATEGIES TO EFFECTIVELY STIMULATE NEW ROCK

This paper will present a methodology being applied which examines well heterogeneity, and designs the diversion strategy based on actual reservoir properties.  Estimations of minimum insitu stress at each cluster are combined with estimates of stress shadow effect both from previous stages and between treatment clusters, to determine at which pressure each cluster will accept fluid.  This data is then used to bin clusters into the ones which will be treated first, followed by a diverter slug, then second and potentially third.  The volume of diverter slug used will be proportional to the number of clusters within the previous bin.



In addition to this, an engineered diversion strategy will look at the perforation design, fracture treatment design and pump rate. The result of this workflow is a tool that will maximize the effectiveness of diverters which ultimately will result in better producing wells at lower completions cost.   This paper will also present case studies of this technique showing validation of it’s success.

 


Kevin Wutherich, Sridhar Srinivasan, Lee Ramsey, 
Robert Downie, and Bill Katon
Drill2Frac
 

$7.50
2018042 USING ENGINEERED DIVERSION STRATEGIES TO EFFECTIVELY STIMULATE NEW ROCK
Price
$7.50
(43) EXPERIMENTAL OPTIMIZATION OF THE FRACTURING TREATMENT DESIGN TO ENHANCE LONG-TERM GAS PRODUCTION IN SHALE FORMATIONS

The study optimizes the effect of the non-ionic surfactant and slugs of low concentration HCl on the near fracture face matrix permeability of Eagle Ford and Marcellus shale by considering different scenarios for the fracturing treatment design. Constant rate flooding apparatus was used to measure the samples base permeability and the permeability after flooding with either slickwater fluid or slickwater with nonionic surfactant or with 3 wt% HCl at 200 oF. The permeability was measured using 3 wt% KCl and at atmospheric temperature.



Three scenarios were considered. The first investigates the pad fluid type effect on the near fracture face matrix permeability. The second scenario investigates the effect of injecting non-ionic surfactant and slugs of 3 wt% HCl on the matrix permeability when a slickwater was used in the pad stage. 

The third scenario is investigating the effect of injecting slugs of 3 wt% HCl on the matrix permeability when non-ionic surfactant is added to the slickwater pad fluid.

 


Aymen Al-Ameri, Texas Tech University

$7.50
2018043 EXPERIMENTAL OPTIMIZATION OF THE FRACTURING TREATMENT DESIGN TO ENHANCE LONG-TERM GAS PRODUCTION IN SHALE FORMATIONS
Price
$7.50
(45) INVESTIGATION OF FAULT AND ITS EFFECT ON BUILD-UP PRESSURE DISTRIBUTION USING NUMERICAL AND ANALYTICAL APPROACHES

The fault effects on the build-up pressure distribution of oil wells were investigated by using numerical and analytical approaches. The limitations and benefits of analytical and numerical solutions of the build-up test were listed in the research. The effects of reservoir boundaries on well responses by using analytical solutions were analyzed. Schlumberger software package “ECLIPSE” was used for the numerical simulation, where the model was discretized to 200 by 200 by 5 grid blocks with the length of each side of the grid block as 75 feet horizontally and 7.5 feet vertically. The model with one production oil well and one injection well with the same characteristics were simulated to prove the well image theory, compare it to the analytical solution and validate the model. The boundary of the reservoir, excluding the fault, was never reached due to the presence of the observation well. Multiple cases, such as one sealing fault, two intersecting faults, semi-permeable faults were analyzed in the model. Horner plots and derivative type curves were built to define the signature of the reservoir. Sensitivity analysis was proposed for each case to provide the correlations between the reservoir parameters. Early time off-trend behaviour in build-up test data by using numerical approach was investigated. Semi-permeable fault signature was defined as the decrease of the slope on the derivative type curve after the establishment of the radial flow. The Horner plot in case of two intersecting faults showed the slope four times more than in case of a homogeneous reservoir.


Serhii Kryvenko, Texas Tech University

$7.50
2018045 INVESTIGATION OF FAULT AND ITS EFFECT ON BUILD-UP PRESSURE DISTRIBUTION USING NUMERICAL AND ANALYTICAL APPROACHES
Price
$7.50
(2019042) A SUCCESSFUL BAKKEN FAILURE REDUCTION PROGRAM

Oasis Petroleum has ~1000 rod pump wells in the Bakken producing from 8000’ - 10,000’. A focused effort has been made over the past few years to reduce the failure rate from ~1.0 failures/well/year to the current rate of .68 failures/well/year. This has been the result of a holistic approach which has encompassed improvements in rod design, surveillance, training, development of Standard Operating Procedures and Best Practices, trialing new technology and POC optimization. This paper will document some of the successes and failures during this journey.


Will Whitley, Matt Chapin, Lauren Coles and Karla Traweek 
Oasis Petroleum

$7.50
A SUCCESSFUL BAKKEN FAILURE REDUCTION PROGRAM
A SUCCESSFUL BAKKEN FAILURE REDUCTION PROGRAM
Price
$7.50
(2019033) ALII (ARTIFICIAL LIFT INTAKE ISOLATION) TOOL, A NEW TECHNOLOGY FOR ISOLATING THE PRODUCTION TUBING ON PUMPING WELLS FOR SAFE AND EFFICIENT ROD AND PUMP CHANGES

The Artificial Lift Intake Isolation (ALII) tool is a new technology for rod pumping wells that when activated isolates the production tubing. The tool provides positive well control prior to breaking wellhead containment providing significant cost savings, safety and environmental protection. The tool is a simple two-part system, the first being the valve portion which is run just below the client’s pump-seating nipple in the production tubing string. The second is the actuator, which runs on the bottom of the insert rod pump. Tool activation is accomplished by simply running a rod pump with the actuator attached. When the pump is seated, the valve is opened for production; and when unseated the valve closes, isolating the tubing. The tool can be cycled multiple times. No additional equipment is required for tool operation and 100% positive shut off is provided which eliminates the need for kill fluids and eliminates the chance of formation gases or other fluids being released at the surface. There is no need for control lines to open and close the tool and there is the capability for utilizing the pump jack to cycle the tool open and closed. The tool also provides the capability for pressure testing the tubing when in the closed position. A number of benefits accrue through application of the tool to pumping wells and includes cost savings from reduced rig time to surface and re-run rod pumps, reduced trucking costs, reduced storage costs for kill fluids and minimizes the number of non-pumping days. Increased safety is realized as the tool provides positive well control prior to a well workover eliminating the chance of formation gases or other fluids being released at the surface. Environmental advantages include reducing the environmental footprint by decreasing water usage saving the local water supply. 


Kent Perry, Gas Technology Institute
Graeme Hines, Donald Slipchuk and Pete Krawiec, Revelation Management, LTD.

$7.50
ALII (ARTIFICIAL LIFT INTAKE ISOLATION) TOOL, A NEW TECHNOLOGY FOR ISOLATING THE PRODUCTION TUBING ON PUMPING WELLS FOR SAFE AND EFFICIENT ROD AND PUMP CHANGES
ALII (ARTIFICIAL LIFT INTAKE ISOLATION) TOOL, A NEW TECHNOLOGY FOR ISOLATING THE PRODUCTION TUBING ON PUMPING WELLS FOR SAFE AND EFFICIENT ROD AND PUMP CHANGES
Price
$7.50
(2019048) AN ECONOMIC AND RISK BASED APPROACH TO OFFSET WELL PREPARATION FOR NEARBY FRACS IN THE DELAWARE BASIN

With the increase in activity in the Delaware Basin, preparing wells for the pressure spikes seen from offset fracs is crucial in order to maintain safe operations.  It is important to take risk and economics into account when deciding how to prep a well. Most importantly, historical data should be factored into the decision making process and used to build the program guidelines.  Factors that should be accounted for are artificial lift type, surface equipment ratings, producing interval, frac azimuth, and 

relative distance and position to the well being fractured.

 


Ryckur Shuttler and Daniel Benavides
Anadarko Petroleum

$7.50
AN ECONOMIC AND RISK BASED APPROACH TO OFFSET WELL PREPARATION FOR NEARBY FRACS IN THE DELAWARE BASIN
AN ECONOMIC AND RISK BASED APPROACH TO OFFSET WELL PREPARATION FOR NEARBY FRACS IN THE DELAWARE BASIN
Price
$7.50
(2019040) ANALYSIS AND OPTIMIZATION OF SUCKER-ROD PUMP DESIGN

Rod lift design methods remain overwhelmingly unchanged since the mid-20th century. Meanwhile, drilling and completion technology has undergone a dramatic transformation. The innovation gap between the two technologies and low-flow artificial lift has resulted in the need for improved design and workflow methods to more effectively operate an unconventional well throughout its lifecycle. New design and workflow processes have been developed that improve upon today’s common practices through the observation of unconventional well characteristics and root cause analysis of equipment failure. This new design and workflow process has resulted in improved performance for unconventional wells in the Permian Basin.


Levins Thompson, Zack Smith and Ricky Roderick
Don-Nan Pump and Supply

$7.50
ANALYSIS AND OPTIMIZATION OF SUCKER-ROD PUMP DESIGN
ANALYSIS AND OPTIMIZATION OF SUCKER-ROD PUMP DESIGN
Price
$7.50
(2019044) APPLICATION OF WATER TREATMENT PROGRAMS TO PREVENT FOULING AND CORROSION DURING DRILL-OUT

Case study of mill-out operations in the Permian Basin which evaluate chemical program 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 injection water and returns at various interval of the mill-out. Effectiveness of chemical treatment was also monitored when biocide was used. Four field case studies are presented for horizontal wells. Two wells were milled-out utilizing workover rigs and two wells were completed using coiled tubing. 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 water treatment program during operations showed significant improvement and sustainable results. Potential corrosion of the work string due to water fouling and composition was also observed, and the effects of changes in chemicals were monitored. This is important because it identified operational improvements that can reduce equipment replacement costs, chemical overuse and protect wells from fouling due to high bacteria. This case study provides a comprehensive review of mill-out operations and provides guidelines for improving chemical efficiency and potential of  extending life of the work string.

 


Tanhee Galindo, GeoKimika Oil & Gas

$7.50
APPLICATION OF WATER TREATMENT PROGRAMS TO PREVENT FOULING AND CORROSION DURING DRILL-OUT
APPLICATION OF WATER TREATMENT PROGRAMS TO PREVENT FOULING AND CORROSION DURING DRILL-OUT
Price
$7.50
(2019028) BEAM VSD ECONOMICS

Variable Frequency Drives (VFD) are a well-known method of pumping beam wells. By running the well continuously and adjusting pumping speed based on pump fillage, they provide unique benefits to reduce failures in difficult environments as compared to operating in pump-off control (POC); these environments might include solids, buckling tendencies at pump-off, and CO2 WAG environments. Although the industry recognizes the VFD benefits, many candidates remain on POC due to the capital investment required for a VFD purchase. This paper discusses two assets within Oxy Permian EOR and analyzes the economics of VFDs in order to assess if expanded usage is justified.


Daniel Lee, Steve Gault and Mike McNeely
OXY USA Inc.

$7.50
BEAM VSD ECONOMICS
BEAM VSD ECONOMICS
Price
$7.50
(2019026) CASE STUDY - USE OF CAPILLARY STRING ASSISTED ARTIFICIAL LIFT AT THE ADAIR SAN ANDRES UNIT

The Apache-operated Adair San Andres Unit (ASAU) currently employs fifteen capillary string (cap string) equipped producing wells, representing 16% of the active producer count. Apache started converting producing wells to cap strings in 2016.  This idea was introduced to Apache at the 2012 CO2 Conference in Midland and later reinforced during a field tour of Whiting’s North Ward Estes CO2 flood in 2015.  The chief benefit using a cap string is production stability.  A review of these installations 

is categorized by a reduction in production variance, meaning an increase in stability - be it oil and gas production, or water-oil and gas-liquid ratio (GLR).  This equates to less rig intervention, more uptime.  Of note: 1) a cap string will successfully operate below the minimum GLR of 400 SCF/BBL/1000’ required by plunger lift, 2) conversion to cap string assisted lift is not affected by the wellbore geometry, and 3) ASAU installations are packer-less.


Rebecca Larkin and Joe Lopez
Apache Corp.

$7.50
CASE STUDY - USE OF CAPILLARY STRING ASSISTED ARTIFICIAL LIFT AT THE ADAIR SAN ANDRES UNIT
CASE STUDY - USE OF CAPILLARY STRING ASSISTED ARTIFICIAL LIFT AT THE ADAIR SAN ANDRES UNIT
Price
$7.50
(2019054) COMPARATIVE STUDY OF WELL SOAKING TIMING (PRE VS. POST FLOWBACK) FOR WATER BLOCK REMOVAL FROM MATRIX-FRACTURE INTERFACE

Water block after hydraulic fracturing is one of the major challenges in shale oil recovery which affects the optimal production from the reservoir. The water blockage represents a higher water saturation near the matrix-fracture interface, which decreases the hydrocarbon relative permeability. The removal of water blockage in the field is typically carried out by soaking the well (i.e., shut-in) after hydraulic fracturing. This soaking period allows water redistribution, which decreases the water saturation near the matrix-fracture interface. However, previous field reports show that there is not a strong consensus on whether shut-in is beneficial in term of production rate or ultimate recovery. Due to the large number of parameters involved in hydraulic fracturing and tight formations, it is challenging to select which parameter plays the dominant role in determining the shut-in performance. Furthermore, literature on field case studies does not frequently report the parameters which are of researchers’ interest. In other words, the challenge of evaluating shut-in performance not only lies on the complexity of parameters and effects involved within the reservoir, but also the limited number of field case studies which report a comprehensive list of fracturing and reservoir parameters.





This paper aims to investigate the effect of well soaking timing on shut-in performance. This question is motivated by the fact that in the field, shut-in can take place either immediately after hydraulic fracturing but before the first flowback (i.e., pre-flowback) or sometime after the first flowback (i.e., post-flowback). The timing of shut-in is believed to influence the production performance, because it dictates how much water will imbibe from the fractures. A numerical core-scale model is built and validated by a successful history match with numerous experimental data. Our model demonstrates that shut-in performed after the first flowback (i.e., post-flowback) can help ensure a higher regained oil relative permeability than shut-in performed before the first flowback (i.e., pre-flowback). A discussion on the water blockage mitigation from these two shut-in timings is also presented. As a result, this study proposes that flowback should be carried out immediately following hydraulic fracturing, even if an extended shut-in is to be performed later.


Nur Wijaya, Texas Tech University

$7.50
COMPARATIVE STUDY OF WELL SOAKING TIMING (PRE VS. POST FLOWBACK) FOR WATER BLOCK REMOVAL FROM MATRIX-FRACTURE INTERFACE
COMPARATIVE STUDY OF WELL SOAKING TIMING (PRE VS. POST FLOWBACK) FOR WATER BLOCK REMOVAL FROM MATRIX-FRACTURE INTERFACE
Price
$7.50