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.
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.
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.
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.
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.
This presentation will discuss a new method of locking out beam pumping unit using a patented and engineered hydraulic sheave lock to support reducing risk at the well site when the pumping unit is shut down for routine maintenance or workovers. It will explore merits of keeping workers entirely out of the swing zone, allowing personnel to accomplish tasks safely and easily, without risk of brake cable failure or slippage resulting in movement of the counterweights. The discussion will focus on how this approach impacts traditional operational practices including an analysis of key metrics encompassing the ability to reduce third party service costs, avoid near miss and serious safety incidents, while also reducing traffic at the well site, resulting in less road damage and carbon emissions. Discussion will focus on how this new process adds value by reducing costs and improving safety for producers.
Due to the ESP motor’s inefficiencies, heat is produced when converting power from electrical to shaft power. This generated heat is either transferred to the surroundings (i.e., through the producing fluids) or absorbed by the motor. In the absence of proper cooling, the motor temperature keeps increasing until either the motor fails or it reaches a temperature high enough to transfer the generated heat to its surroundings. According to the Arrhenius rule, equipment life is expected to reduce in half for every 18°C increase. Proper heat transfer not only avoids overheating failures but also improves the system’s reliability. A survey of the open literature was performed to evaluate how the industry approaches the heat transfer problem for ESP motors. The studies were divided into six different categories. A recurrent approach is to enhance temperature ratings of internal components in the motor and perform field trials to verify an increase in reliability. Although this is a sound practice from a commercial point of view, it does not provide any insight. This review recovers simple theoretical models enabling a more fundamental understanding of ESP motor heat transfer behavior in complex scenarios. It also elucidates areas where knowledge is still lacking, particularly in two-phase flow conditions around the motor.
A revolutionary packer-type gas separator was designed to improve gas separation efficiency downhole. A deep analysis of gas separation methods was done to better understand the nature of the process and to design a tool that could generate enhanced conditions for the gas separation phenomenon. During the research stages where data from Permian fields were analyzed to develop this new design of gas separator, the engineering team found three main challenges in downhole gas separation. The first one was the wells were being converted from ESP to rod pump earlier, forcing the downhole gas separators to handle more production than before. The second is the small production casing size that usually is 5.5” casing, which significantly reduces the annulus area that is vital to get an effective gas separation efficiency, and finally, the gas slugging behavior, which in high proportion can lead to a gas lock-in sucker rod pump systems. Following the requirements and limitations, a packer-type gas separator was designed, built, and tested in oil wells. This gas separator has an outlet section of 1.89” OD, which means the design maximizes the gas separation area where it really matters at the fluid outlet point. The innovative fluid exit slots design creates a linear flow path allowing gas to separate and flow upward the casing annulus in a natural way. Additionally, a valve below the cup packer was included to eliminate surging in wells. This valve prevents surging by holding the fluid in the vertical section, thus avoiding backflow when the gas slug leaves liquids behind. To evaluate the new design, a calculator was developed to estimate the gas separation efficiency downhole and compare the gas separation efficiency among different gas separators. After the implementation of this design in 5 wells, the results confirmed the high gas separation efficiency obtained with this new gas separator configuration. The novelty of this gas separator design is the outlet section that takes advantage of the gravity force to increase the gas separation efficiency without limiting the tensile strength of the BHA. Also, the fact of including a valve to address the surging condition in the well before the fluids go through the gas separation is a new approach in a gas separation tool.
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.
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.
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.