This paper presents statistics for remedial stimulation work performed at the Willard Unit since 1986. It also discloses how stimulation candidates are chosen, what stimulation fluids are used at present, and how stimulation work is tracked. The Willard Unit is a San Andres carbon-dioxide flood located in the north-central portion of the Wasson field near Denver City, Texas. The Unit produced under primary from the mid 1930's until the start of water-flood operations in the mid 1960"s. Tertiary operations commenced in 1985 with the injection of carbon dioxide into approximately two thirds of the unit which is comprised of 340 producers and 260 injectors. The San Andres at the Willard Unit is a dolomite found at a depth of about 5100". Gross pay averages 150", porosity averages 8.5%, and permeability averages 1.5 md. The majority of wells are cased to 1 D and perforated with 15 to 20 holes. Producers have been sand fractured, and injectors have been either sand fractured or gelled-acid fractured.

Magnetic Flux density (MFD) technology is a safe and accurate means of locating and monitoring variations within the body wall of tubing and casing products. Older technology utilizing Gamma Radiation to identify these problems is very hazardous, typically produces limited results, and is physically limited to effectively evaluating only 6% to 12% of the total tube body. Improved MFD technology can offer a safe and effective method to evaluate 100% of the tube body for wall loss from corrosion, tool cuts, and sucker rod wear.

The complexity and cost of exploring for oil and gas has increased significantly in the past few years due to Intelligent Wells, Multilaterals and Heavy Oil field developments. New challenges for drilling, completing, producing, intervening in a well, environmental regulations, and wide swings in the price of oil have changed the role of technology in the oil fields. The industry is relying on technology to affect the costs of exploring for hydrocarbons in the following ways: - Reduce operating expenses (OPEX) by automating the processes used to explore and produce hydro - lncrease net present value (NPV) by providing systems that enhance the recovery of hydrocarbons f carbons, reducing the frequency of unplanned intervention, and improving information and knowledge management to decrease operating inefficiencies. From reservoirs. The new technologies improve production techniques to delay and/or reduce the production of water from downhole drilled and that will reduce the number of surface facilities required. The surface equipment requirements to handle increasingly larger quantities of hydrocarbons at these facilities should also decrease with the implementation of new technologies. - Reduce capital expenditures (CAPEX) by creating processes that will decrease the number of wells New processes for drilling, completion, production, artificial lift, and reservoir management have been created by advancements in technology in fields such as high temperature sensory, downhole navigation systems, composite materials, computer processing speed and power, software management, knowledge gathering and processing, communications and power management. Horizontal drilling and new fracture techniques have allowed operators to produce hydrocarbons profitably from areas that were uneconomical just a few years ago. Sensor technology in conjunction with data communications techniques provide on-demand access to the information necessary to optimize hydrocarbon production levels and achieve costs goals. Surface and downhole sensors are changing the way hydrocarbons are produced by optimizing production from downhole, supporting extend the life of artificial lift systems and providing information used to update reservoir and production models. A new technology that combines sensors with wireless telemetry provide the operators with new versatility and capability to place sensors in areas of the wellbore that were prohibitive due to technical difficulties and/or economic justification. The ability to communicate in and out of the wellbore using wireless systems can increase the reliability of the production system and decrease the amount of time required for the installation of the completion hardware in the wellbore. The elimination of cables, clamps, external pressure and temperature sensors, as well as splices on the cable that can fail inside the wellbore provides a significant advantage when attempting to place sensors in wellbores to monitor production or to optimize the pumps used in Artificial Lift applications.

Automation electronics manufacturers have been focusing a great deal of their development efforts on the plunger lift control application during recent years. The objective has been to automate this process

Real time analysis and visualization of the performance of a rod pumped well are achieved using multiple small and

compact wireless sensors that simultaneously transmit acquired data to a digital laptop manager that integrates the

measurements, displays performance graphs and provides advanced tools for analysis and troubleshooting of the

pumping system.

Battery powered wireless sensors for fluid level, pressure and dynamometer data acquisition are easily deployed and

quickly installed on the well. The laptop manager automatically recognizes and commissions the sensors. The user

sets up and controls the acquisition of data which may include multiple sensors that synchronously monitor variables

such as tubing and casing pressures, fluid level and polished rod acceleration/position and load as a function of time.

Elimination of cables and connectors improves the reliability of the hardware and data while speeding up the set-uptear-

down process. The user interface presents a smart instrument rather than a complex application.

Among the many innovations provided by these well performance analysis tools stand out the real time visualization

of the operation and fluid distribution in the down-hole pump, the simultaneous display of quantitative surface and

pump dynamometer graphs in conjunction with fluid level and wellbore pressures. Acquired data, wellbore

description and pumping system characteristics are saved as a historical data base creating a continuum of the well's

information and performance for direct comparison and detailed analysis.

The paper describes the hardware and user interface, the procedures for installation and acquisition and several

examples of field data and well performance analyses for a variety of rod pumping installations.

Development of the REDA PC progressing cavity electric submersible pumping system began in 1991. The primary driving force behind this product development was the problem of accelerated wear of sucker rods and production tubing in deviated and horizontal wells when using surface driven progressing cavity pump systems. Many producers were replacing sucker rod and production tubing strings multiple times per year. This was severely affecting the economic viability of the oil wells. Since May 1994, REDA PC units have been installed in over 60 oilwells. The main cause of pulling the pumping system has been pump life. The harsh downhole conditions reduce the pump"s, ability to produce fluid while the REDA PC drive system is normally unaffected. As a result, a customer requested that a system be designed that would allow the pump to be pulled and replaced while leaving the bottom drive system undisturbed. This paper will describe the tubing deployed REDA PC system and explain the wireline retrievable configuration, the in-well testing to date, and the future developments for the system.

The "Wolfberry" play is named after the two main productive formations, the low-permeability Wolfcamp and Spraberry, and is a very large part of the everyday business in the Permian Basin. Activity in the Wolfberry has recently increased, spurred by the current relatively strong oil prices. However, the economic foundation of these producing wells is their stimulation and the management of completion costs. All of these wells require multistage fracture treatments to achieve economic production and therefore significant effort has been given to continuous improvement in efficiently completing and fracturing Wolfberry wells. To illustrate the evolution of the optimization process, a retrospective of the changes implemented in fracturing Wolfberry wells over the past 10 years in several counties in the Permian Basin is presented. This paper addresses in particular, choices involved in optimizing stimulation stages (including perforation schemes), treatment fluids and proppants, to maximize net present value contribution of the hydraulic fracturing treatments.

One of the most common problems encountered in designing a stimulation treatment is a low working pressure rating of surface equipment. Quite often, tubular goods are capable of much higher working pressures than the wellhead equipment, and the primary limit of pressure and injection rate is above ground. Breakdown and "Ball Out" treatments are often restricted by low working pressure ratings when the maximum allowable pressure at the pump is less than the pressure required to inject fluid into new or fluid-damaged perforations. Even though high pressures may be required for only a few minutes, it is vital to successful completion of a well that each perforation or zone be opened. Pressure limitations can be especially critical since the fracture area developed and proppant transport are direct functions of injection rate. When the pressure limiting component of a well system is above ground it can usually be "upgraded" safely and reliably by one of these methods: 1. Isolating the wellhead from treating pressure 2. Substitution of a "Treating Tree" for the production Christmas tree 3. Special landing joints or "Top Out Joints" for working through blow out preventers or wellhead assemblies where conventional trees have not been installed. Each of these methods has its strong and weak points and warrants detailed examination.

Almost everyone connected with the oil and gas business will, at one time or another, be faced with rules and regulations governing oil and gas operations. The purpose of this paper is to present a generalized concept of some of the laws adopted by the various regulatory agencies in Texas and New Mexico. To completely encompass all rules and regulations in effect in the space and time allotted would be impossible. But, by supplementing the information contained in this paper with the reader's own knowledge and that available from other sources, one may gain a broader perspective of this particular phase of the oil and gas industry as well as a more complete understanding of the workings of the regulatory bodies.

Continuous coil tubing has become a viable alternative to the conventional workover method of injection well cleanout. With the increase in the wellhead price of oil, a greater emphasis is placed on the efficiency of in-place waterfloods. When an injection well within a flood becomes plugged, the method by which the well is monitored should indicate if there is a problem. Based on that indication and all available relevant data, a decision can be made as to the kind of problem which has developed and likely methods of correcting that problem. The use of coil tubing in many cleanout procedures is a cost- and time saving method. The circulation method is accomplished without the need of moving or disconnecting any part of the injection string. The wells do not have to be backflowed and stimulation jobs can be done with minimum exposure of the injection string to the corrosive effects of acid. A treatment technique can be designed to correct or counteract problems within the injection profile on a point-to-point basis.

There are many potential failures in production wells which result from corrosive downhole environments, mechanical aspects of artificial lift or a combination thereof. Tubing failures constitute a costly failure mechanism in production wells. Tubing inspections can provide valuable insight on the condition of tubing as well as the distinction between causes of tubing degradation. This information is utilized to replace worn and pitted tubing joints, failure root cause analysis and implement solutions to mitigate future failures. Due to the high cost of a tubing failure, a high-quality tubing inspection is critical to identify potential failure mechanisms in a used tubing string. This paper serves to discuss the engineering and economic benefits of a tubing scanning program. The results of an in-plant inspection compared to an EMI wellhead inspection on two Anadarko wells in the Permian Basin exemplifies said benefits. This paper provides an in depth analysis of tubing inspection technology, the pros and cons of both wellhead and in-plant inspections and data utilization to reduce downhole failures.

High gas-liquid formation ratios appear as the fluid level decreases and as a result significant decreases in pumping efficiency are seen in the ESPs. This problem force frequent shutdowns in the pump because the gas is incapable of adequately cooling the motor and this forces the companies to maintain high fluid levels to avoid the formation of free gas at the pump intake, which increases the PIP and limits the production of fluid. A new and innovative downhole gas separator has been introduced in recent applications to treat gas slug’s problems. For these applications, a shrouded ESP with a double stage of gas separation connected to the bottom of the shroud as an intake was designed to break and separate gas slugs and avoid gas entrance into ESPs by forcing free gas to go around the shroud and produce through the casing. The gas separator uses an innovative design to break the gas slugs in the annular section between the casing and the tool, additional with the internal dual flow system the separation efficiency increases while it’s created a chamber lift filled with free gas liquid.  

With this new system, the fluid is now forced to pass through an additional gas separator which helps to separate gas and keeps lower PIP than usually promoting the fluid production in the wells.

 

When an insert rod pump gets stuck in tubing there will be a significant increase in well-servicing events. These events cost the consumer money and also places the worker's safety at risk. 

The Highway 80 area reviewed the number of stuck rod pumps in tubing conditions that had occurred from 2010 to mid-2017.  In total, there were 825 pumps that were unable to be pulled with rods, which resulted in tubing being pulled to retrieve the pump. To try and resolve this issue Pioneer used a rubber fin element below the discharge of their insert rod pumps. By doing so they saw a reduction in stuck pumps with the rubber element. Even though this method decreased the number of stuck pumps, about 10% of their pumps continued to get lodged in the tubing. 

In the third quarter of 2017, Harbison-Fischer implemented a design change to these wells. The Harbison-Fischer Brush Sand Shields were installed to all insert pumps going forward.

This paper will discuss the early results of approximately 18 months since the first Brush Sand Shields were installed. We will compare the pumps pulled that were stuck in tubing with and without the design change since the implementation. Our goal is to continue to review the trend to see if positive results are achieved. We will track the data and present it again in 2020. We have calculated that the additional cost of pulling tubing is more than 50% more than if the pump can be retrieved with the rods.

 

Replacing bridge plugs with Perf PODs, to plug/divert individual perforations, allows Operators to divert the stimulation mid-stage and reduce the total number of bridge plugs within a wellbore while maintaining the advantages of closer stage spacing and adding additional clusters.  The risk of a pre-set plug can be drastically reduced, along with pump down time, completion cost and resources associated for the corresponding wireline runs and subsequent millout work.  Applying Perf POD diversion technology between bridge plugs allows the Operator to achieve maximum cluster efficiency, while stimulating the entire stage, without leaving orphan clusters behind.  This ensures a more consistent stimulation volume pumped into each perforation cluster, ultimately providing a more balanced treatment and reducing the probability of a “runway frac”, which could potentially damage offset wells.   

Based on current stimulation design - are you effectively stimulating every cluster?

 

Slippage is required for lubricating the plunger/barrel within beam pumping systems. Increasing pump clearance increases the amount of slippage, which may lead to inefficient operations. Operators could run their field more efficiently through decreasing failure rate and increased electrical cost savings by calculating the optimum design using the Patterson Slippage equation for individual well conditions. This paper will discuss the economic tradeoffs with changing pump clearances and recommend theoretical optimum designs given well conditions. The paper will also include nomographs and a calculator to recommend optimum designs. 

The performance of Harbison-Fischer’s patented Sand Flush Plunger (SFP) was assessed relative to the average runtime for standard API plungers in the HWY 80 field, operated by Pioneer Natural Resources (PNR). The field case study captured information from Harbison-Fischer’s pump-tracker for 5,283 wells and 32,804 workover records dating back to 1989. As of the record date, 1,934 different wells had used an SFP 3,473 times. The analysis focused on 194 wells, for each of whom the data showed at least one failure originated by the pump for each of the two plunger types. The average runtime for the SFP and the API plungers were found to be 1,178 days and 579 days respectively.

The present study constitutes an update on the continuous monitoring of the performance of the SFP that has been carried out in HWY 80 field since 2015 [1]. The number of wells considered for calculating the average runtimes has gone up by 37 wells from 157 reported in 2015. Similarly, the number of qualifying pump changes has increased by 102 from 486 reported back in 2015. The data processing has been carried out using Tableau, and slightly different criteria for cleaning the records have been implemented.

In 2014 Oxy EOR had lost confidence in the accuracy of Fluid Levels in CO2 wells and was not shooting them. Echometer and Oxy collaborated to identify the root cause of the fluid level inaccuracy and resolve the issue through improved procedures and educating personnel. Today trusted fluid level information adds value by improved operational decision making. 

Typically, the Petroleum Industry maintains operational ideas that were developed years ago.  These operational ideas may still have merit, but some improvements should be considered.  Sucker rod guides are an example of such practices.  Most production companies continue to use rod guide material that was introduced at the conception of the recognition of the need for sucker rod guides.  This presentation will give information of new materials and new application ideas for sucker rods guides. 

The cavitation phenomenon has been extensively studied for many years, however, guidelines on how to implement this existing knowledge to the actual operation of the jet pumping systems in the oilfield are not abundant and, as per the author can see it, not yet being presented in such way that the people that operate these systems in the oilfield could implement on a straight forward way. It has been proven that using a scientific and easy to follow methodology, it is possible to prevent jet pump operating problems related to cavitation, during the early, middle and late stage of the well production life. Preventative and Corrective methodologies are based on: Measured production rates, power fluid rate and pressure, gas to liquid ratio, jet pump seating depth and jet pump nozzle/throat combination.

This paper presents a straight forward discussion on the jet pump cavitation, its hydrodynamics, causes, identification, potential damage, consequences on the jet pump performance and methods to predict it and avoid it.

The ESP system is a mechanical/electrical/hydrodynamic system. It is costly when it fails as the tubing has to be pulled and much or all of the equipment is replaced. 

This paper points out tips in the below various areas that if considered are likely to increase the average run life of ESP Systems

-Failure definitions from data

-Design

-Installation

-SCADA-Monitoring

-Tips for running in Harsh Conditions

-Pulling

-Teardown Analysis

-RCFA and follow up

The information summarized includes industry findings and experience from the author’s backgrounds

In some of today’s unconventional wells, sucker rod pumping systems are facing challenges related to excessive wear, affecting production and increasing operational costs. One of the reoccurring damages in a sucker rod pumped well occurs near the kick-off point in a deviated well between the coupling and the tubing or between the sucker rod and the tubing; the metal-to-metal contact causes hole-in-tubing failures and operators have been seeking solutions to mitigate or minimize excessive tubing wear in highly deviated wells. Wear caused by both metal contact and abrasive particles, as well as corrosive attack from the wellbore’s fluid also affects the metal integrity of the tubing, coupling and sucker rod. It is beneficial to develop fundamental understanding on wear and friction concepts in rod lift applications, to optimize rod lift product designs and improve Mean Time Between Failures (MTBF) in deviated wells.

In this paper, the concepts of friction and wear will be explained from applied rod lift engineering perspective. Field tested solutions to reduce tubing wear will be presented with lab and field data.