Rod pumps with isolated tailpipe systems have been growing in popularity over the past few years and applied in basins all over the US.  Some earlier system component designs had vital shortcomings that became more evident over time with the growing install base.  
The important fact is that these lessons learned have been a driving force in making positive strides to improve installation procedures, component design, and material selections.  Another vital element leading to improved consistencies and better results is an accelerated and expanded knowledge regarding the required nodal analysis to properly predict required production and reservoir properties to yield optimal system function. 

This paper will cover the process that has been endured to get to the current improved state of operations and how further success is assumed to be obtained as rod pumps with isolated tailpipes are applied in unconventional wells for years to come. 
 

A casing gas separator (CGS) is a safe to run, low-risk, and efficiency altering tool that pairs naturally with existing wellbore design and work practices to vastly improve gas handling and capacity in virtually any form of artificial lift.

When a new well is drilled the hole is cased and cemented and during that process a CGS is run permanently into place on the casing with no alteration to the drilling program whatsoever.  The CGS is commonly placed at kickoff point or in a tangent further downhole and well work occurs with absolutely no alteration to normal completion processes.  

A CGS may be run and set with multiple flowpath options and separation capacity is essentially doubled by providing twice the casing flow area inside the tool.  The result is the most prolific and flexible gas separation technology any horizontal well has ever applied. 
 

Relating Polished Rod Velocity and ratio of MPRL/PPRL to Failure Frequency. This study uses historical data to understand these relationships. The data is primarily from San Andres and Clearfork water floods and CO2 floods located in the Permian Basin.

Historically as many as 30% of bottom hold down pumps have been stuck. This can result in extra cost associated with pulling tubing on pump repairs or rod failures. This paper focuses on efforts with various tools and techniques that have been used to lessen the number of pumps stuck in tubing.

New unconventional wells have been a huge challenge for ESPs in the Permian Basin because in horizontal wells with high-formation GORs or GLRs, the pumped fluid can cause issues such as gas interference, gas locking, short run life, low production, poor energy efficiency, increased failure rates, shutdowns, so forth. A major problem is gas presence around the ESPs, it causes the motor to rapidly overheat because the gas is incapable of adequately cooling.

For this application, a double stage of gas separation was designed to break the gas slug and avoid gas entrance into ESPs by forcing free gas to go around the shroud and produce through the casing, and the fluid is forced to pass through an additional gas separator (Guardian Shield), this tool helps to separate gas to keep lower motor temperature. These novel applications help operators to reduced OPEX (operating expense) by minimize well Interventions, decreasing failures in the pump due to overheat, and allow the ESP to operate in gassy wells with high GLR, stabilizing the production and reduce the unforeseen interruption.
 

Pumping wells hard involves a tradeoff between operating cost and production. Increased idle time or holding additional back pressure on the reservoir can decrease production but pumping a well harder will likely increase failure frequency. The existing reservoir pressure has a significant impact on the potential change in production.  Pump-Off Controllers (POCs) are used to regulate run time on many wells operated in Permian Basin water floods and are accepted as a failure reducing and cost saving tool. Moving set points in, changing the pump off strokes, and decreasing SPM should not affect production. Notably, conventional inflow models demonstrate that reductions in flowing bottom-hole pressure become less impactful when wells are operated at relatively low bottom-hole pressures. This paper will discuss specific examples of using POCs to pump wells gently and illustrate one mythology or calculator to evaluate the economic tradeoff.

Producers are continuously challenged to keep drilling costs as low as possible and retain operational flexibility so as not to compromise completion and production performance. Well construction cost reduction strategies that include a casing size reduction can cause long-term production inefficiencies. Smaller casing sizes impact the critical liquid lifting velocity necessary to support efficient artificial lift thereby compromising production. If during the lifting phase, critical liquid lifting velocities are exceeded in the production annulus above the downhole pump, the producing bottomhole pressures become higher, and the producing rates consequently lower.  Preventing the risk of critical liquid lifting velocities in the production annulus maximizes drawdown and production.

This paper demonstrates a low risk, cost-effective modification to a standard 5 ½ inch monobore casing design can effectively control critical liquid lifting velocities occurring during the production lifting phase. The paper shows and analyze field studies from Producer’s currently implementing this approach.
 

Downhole sucker rod pump clearance changes from shop conditions to bottom hole conditions due to bottomhole pressure and temperature that the pump components are subjected to. Presented here are equations to estimate the change in dimensions of the plunger and barrel of top and bottom hold down pumps at bottomhole pressure and temperature conditions. The approach uses one equation for cylinder dimension changes with pressure with appropriate inputs for the internal and external pressure (or average pressure) for the upstroke when slippage is important and has an effect on the total production.  Examples are given for thin and heavy wall pumps at a variety of depths, pressures, and temperatures. Corresponding production rates for the calculated downhole pump dimensions are given.

Rod wear and corrosion have a complex relationship that is often misunderstood of oversimplified.  This paper provides a technical framework and provides empirical evidence of principles that clarify this complex relationship.  In particular, this paper will review stress levels and metal failure mechanisms that dispel many commonly held beliefs.  A better understanding of these principles will lead to opportunities to reduce an operator’s total operating footprint.

Automation of rod pumping systems has been a part of the oil and gas industry for over 65 years.  Starting with time clocks in the 1950s, the invention of the pump-off controller in the 60s, and variable speed drives in the early 2000s, the amount of technology available to both control and analyze the system has increased and improved drastically. Several of the driving factors to automate include high initial production rates, followed by a steep decline, gas slugging, high degrees of rod and tubing friction, and paraffin build.  This paper will detail several of the automation packages and features that are available on the current market, the applications of each feature, and how they can be beneficial in preventing premature failures of the main components involved in a rod lift system.

The most common form of artificial lift is sucker-rod pumping.  One of the main elements of rod lift system design is the selection of a downhole pump.  This study examines the various factors that affect the selection and design of downhole rod pumps. Downhole rod pumps are made up of five main components: barrel, plunger, balls and seats, seating assembly, and valve rod or pull tube.  Understanding the various well and system design factors that are examined when selecting each of these components is a crucial part in the design of the downhole pump. The dynamics that affect metallurgy, length, diameter, and pump configuration of the critical components are examined within this study. Once the aspects that affect material selection have been evaluated the different applications of API and specialty pumps are considered. By following the procedures and methodology outlined in this study, proper downhole pump selection can be implemented and the risk for premature pump failures is mitigated.

Gas lift is becoming a popular form of artificial lift in the Permian Basin for long horizontal wells that make high gas rates. Unfortunately the decline curves on most horizontal wells are not ideal. As the rates and pressure quickly drop gas lift starts to become inefficient and we are forced to make artificial lift changes in order to preserve base production. Rod pumps have always been the end of life application for artificial lift but it has been proven that pumping in horizontal wells can be very costly due to wellbore conditions. This paper will explain the issues with rod pumping in horizontals and why we decided to convert to gas assisted plunger lift before we convert to rod pump.

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.  
 

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.

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

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.

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.
 

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.
 

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.
 

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.
 

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.
 

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.

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.

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.

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.